ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934

For
the fiscal year ended December 31, 2008

OR

¨

TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934

For
the transition period from
to

Commission
File No. 001-07775

________________________

MASSEY
ENERGY COMPANY

(Exact
name of registrant as specified in its charter)

____________

Delaware

95-0740960

(State
or other jurisdiction of incorporation or organization)

(I.R.S.
Employer Identification Number)

4
North 4th Street, Richmond, Virginia

23219

(Address
of principal executive offices)

(Zip
Code)

Registrant’s
telephone number, including area code: (804) 788-1800

Securities
registered pursuant to Section 12(b) of the Act:

Title
of each class

Name
of each exchange on which registered

Common
Stock, $0.625 par value

New
York Stock Exchange

Securities
registered pursuant to Section 12(g) of the Act:

None

Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act. Yes x No ¨

Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d) of the Act. Yes ¨ No x

Indicate
by check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements for
the past 90 days. Yes x No ¨

Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K (§229.405 of this chapter) is not contained herein, and will not
be contained, to the best of registrant’s knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. ¨

Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer or a smaller reporting company. See
the definitions of “large accelerated filer,” “accelerated filer,”
“non-accelerated filer” and “smaller reporting company” in Rule 12b-2 of the
Exchange Act (Check One):

Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act). Yes ¨ No x

The
aggregate market value of the common stock held by non-affiliates of the
registrant on June 30, 2008, was $7,571,508,750 based on the last sales price
reported that date on the New York Stock Exchange of $93.75 per share. In
determining this figure, the Registrant has assumed that all of its directors
and executive officers are affiliates. Such assumptions should not be deemed to
be conclusive for any other purpose.

Part III
incorporates certain information by reference from the registrant’s definitive
proxy statement for the 2009 Annual Meeting of Stockholders, which proxy
statement will be filed no later than 120 days after the close of the
registrant’s fiscal year ended December 31, 2008.

Forward
Looking Statements

From time
to time, Massey Energy Company, which includes its direct and wholly owned
subsidiary, A. T. Massey Coal Company, Inc, and its direct and indirect wholly
owned subsidiaries (“we,” “our,” “us”), makes certain comments and disclosures
in reports, including this report, or through statements made by our officers
that may be forward-looking in nature. Examples include statements related to
our future outlook, anticipated capital expenditures, projected cash flows and
borrowings and sources of funding. We caution readers that forward-looking
statements, including disclosures that use words such as “believe,”
“anticipate,” “expect,” “estimate,” “intend,” “may,” “plan,” “project,” “will”
and similar words or statements are subject to certain risks, trends and
uncertainties that could cause actual cash flows, results of operations,
financial condition, cost reductions, acquisitions, dispositions, financing
transactions, operations, expansion, consolidation and other events to differ
materially from the expectations expressed or implied in such forward-looking
statements. Any forward-looking statements are also subject to a number of
assumptions regarding, among other things, future economic, competitive and
market conditions. These assumptions are based on facts and conditions, as they
exist at the time such statements are made as well as predictions as to future
facts and conditions, the accurate prediction of which may be difficult and
involve the assessment of circumstances and events beyond our control. We
disclaim any intent or obligation to update these forward-looking statements
unless required by securities law, and we caution the reader not to rely on them
unduly.

We have
based any forward-looking statements we have made on our current expectations
and assumptions about future events and circumstances that are subject to risks,
uncertainties and contingencies that could cause results to differ materially
from those discussed in the forward-looking statements, including, but not
limited to:

(i)

our
cash flows, results of operation or financial
condition;

(ii)

the
successful completion of acquisition, disposition or financing
transactions and the effect thereof on our business;

our
interpretation and application of accounting literature related to mining
specific issues; and

(xxviii)

the
successful implementation of our strategic plans and objectives for future
operations and expansion or
consolidation.

We are including this cautionary
statement in this document to make applicable and take advantage of the safe
harbor provisions of the Private Securities Litigation Reform Act of 1995 for
any forward-looking statements made by, or on behalf, of us. Any forward-looking
statements should be considered in context with the various disclosures made by
us about our businesses, including without limitation the risk factors more
specifically described below in Item 1A. Risk Factors of this Annual Report on
Form 10-K.

Our 2009
Annual Meeting of Shareholders will be held at 9:00 a.m. EDT on Tuesday, May 19,
2009 at The Jefferson Hotel, 101 West Franklin Street, Richmond, Virginia
23220.

ii

Part
I

Because
certain terms used in the coal industry may be unfamiliar to many investors, we
have provided a Glossary of Selected Terms beginning on page 19 at
the end of Item 1. Business.

Item
1. Business

Business
Overview

We are
one of the premier coal producers in the United States. In terms of produced
coal revenue in 2007, we are the fourth largest United States coal company in
terms of produced coal revenue, according to Energy Ventures Analysis, Inc.
(“EVA”). According to EVA, we are the largest coal company in Central
Appalachia, our primary region of operation, in terms of tons produced and
total coal reserves in 2007.

We
produce, process and sell bituminous coal of various steam and metallurgical
grades, primarily of a low sulfur content, through our 23 processing and
shipping centers (“Resource Groups”), many of which receive coal from multiple
mines. At January 31, 2009, we operated 66 mines, including 46 underground mines
(two of which employ both room and pillar and longwall mining) and 20 surface
mines (with eleven highwall miners in operation) in West Virginia, Kentucky and
Virginia. The number of mines that we operate may vary from time to
time depending on a number of factors, including the existing demand for and
price of coal, exhaustion of economically recoverable reserves and availability
of experienced labor.

Customers
for our steam coal product include primarily electric power utility companies
who use our coal as fuel for their steam-powered
generators. Customers for our metallurgical coal include primarily
steel producers who use our coal to produce coke, which is in turn used as a raw
material in the steel manufacturing process.

Key
statistics for 2008 include:

·

Produced
coal revenues increased by 25% from $2.1 billion in 2007 to $2.6 billion
in 2008 on produced coal sales of 41.0 million
tons.

·

Reserve
base of approximately 2.3 billion tons at December 31,
2008.

A.T.
Massey was originally incorporated in Richmond, Virginia in 1920 as a coal
brokering business. In the late 1940s, A.T. Massey expanded its business to
include coal mining and processing. In 1974, St. Joe Minerals acquired a
majority interest in A.T. Massey. In 1981, St. Joe Minerals was acquired by
Fluor Corporation. A.T. Massey was wholly owned by Fluor Corporation from 1987
until November 30, 2000. On November 30, 2000, we completed a reverse spin-off
(the “Spin-Off”) which separated Fluor Corporation into two
entities: the “new” Fluor Corporation (“New Fluor”) and Fluor
Corporation which retained our coal-related businesses and was subsequently
renamed Massey Energy Company. Massey Energy Company has been a
separate, publicly traded company since December 1, 2000.

Industry
Overview

Coal
accounted for 24% of the energy consumed (excluding
certain alternative fuels including wind, geothermal and solar power generators)
by the United States and 29% of energy consumed globally in 2007,
according to the BP Statistical Review of World Energy (“BP”). In 2007, coal was
the fuel source of 49% of the electricity generated nationwide, as reported
by the Energy
Information Administration (“EIA”), a statistical agency of the United States
Department of Energy.

According
to BP, in 2007, the United
States was the second largest coal producer in the world, exceeded only by
China. Other leading coal producers include Australia, India, South Africa, the
Russian Federation and Indonesia. According to BP, the United States has
the largest coal reserves in the world, with proved reserves totaling 243
billion tons. The Russian Federation ranks second in proved coal reserves with
157 billion tons, followed by China with 115 billion tons, according to
BP.

United States coal
reserves are more plentiful than oil or natural gas with 234 years of supply at
current production rates. Proved United States reserves of oil amount to 12
years of supply at current production rates and proved United States
reserves of natural gas amount to 11 years of supply at current levels of
consumption, as reported by BP.

1

United
States coal production has more than doubled over the last 40 years. In 2008,
total United States coal production, as estimated by the EIA, was 1.2 billion
tons. The primary producing regions by tons were as follows:

Region

% of Total

Powder
River Basin

46%

Central
Appalachia

20%

West
(other than Powder River Basin)

11%

Northern
Appalachia

11%

Midwest

9%

All
other

3%

Total

100%

The EIA
estimated that approximately 69% of United States coal was produced by surface
mining methods in 2007. The remaining 31% was produced by underground mining
methods, which include room and pillar mining and longwall mining (more fully
described in Item 1. Business, under the heading “Mining Methods”).

Coal is
used in the United States by utilities to generate electricity, by steel
companies to make steel products, and by a variety of industrial users to
produce heat and to power foundries, cement plants, paper mills, chemical plants
and other manufacturing and
processing facilities. Significant quantities of coal are also exported from
both East and Gulf Coast terminals. The breakdown of United States coal
consumption for the first ten months of 2008 as estimated by the EIA, is
as follows:

End
Use

% of Total

Electric
Power

93%

Other
Industrial

5%

Coke

2%

Residential
and Commercial

<1%

Total

100%

Coal has
long been favored as an electricity generating fuel because of its basic
economic advantage. The largest cost component in electricity generation is
fuel. This fuel cost is typically lower for coal than competing fuels such as
oil and natural gas on a Btu-comparable basis. The EIA estimates the
average cost of various fossil
fuels for generating electricity in the first 11 months of 2008 was as
follows:

Electricity
Generation Source

Average Cost
per million BTU

Petroleum
Liquids

$ 16.56

Natural
Gas

$ 9.34

Coal

$ 2.06

Petroleum
Coke

$ 1.85

There are
factors other than fuel cost that influence each utility’s choice of electricity
generation mode, including facility construction cost, access to fuel
transportation infrastructure, environmental restrictions, and other factors.
The breakdown of United States electricity generation by fuel source in 2007, as
estimated by EIA, is as follows:

Electricity
Generation Source

%
of Total

Electricity Generation

Coal

49%

Natural
Gas

21%

Nuclear

19%

Hydroelectric

6%

Oil
and other (solar, wind, etc.)

5%

Total

100%

2

Demand
for electricity has historically been driven by United States economic growth
but it can fluctuate from year to year depending on weather patterns. In 2008,
electricity consumption in the United States decreased 0.4% from 2007,
but the average growth rate in the past decade was approximately 1.3% per
year according to EIA estimates. Because coal-fired generation is used in
most cases to meet base load requirements, coal consumption has generally grown
at the pace of electricity demand growth.

According
to the World Coal Institute (“WCI”), in 2007 the United States ranked seventh
among worldwide exporters of coal. Australia was the largest exporter, with
other major exporters including Indonesia, the Russian Federation, Columbia,
South Africa and China. According to EVA, United States exports increased by 37%
from 2007 to 2008. The usage breakdown for 2008 United States coal exports of 80
million tons was 47% for electricity generation and 53% for steel production. In
2008, United States coal exports were shipped to more than 30 countries. The
largest purchaser of United States exported utility coal in 2008 continued to be
Canada, which took 19.1 million tons or 50% of total utility coal exports. This
was up 31% compared to the 14.6 million tons exported to Canada in 2007. Overall
steam coal exports increased 43% in 2008 compared to 2007. The largest
purchasers of United States exported metallurgical coal were Brazil, which
imported approximately 5.9 million tons, or 14%, and Canada, which imported 3.7
million tons, or 9%. In total, metallurgical coal exports increased 31% in 2008
compared to 2007.

Depending
on the relative strength of the United States dollar versus currencies in other
coal producing regions of the world, United States producers may export more or
less coal into foreign countries as they compete on price with other foreign
coal producing sources. Likewise, the domestic coal market may be impacted due
to the relative strength of the United States dollar to other currencies, as
foreign sources could be cost-advantaged based on a coal producing region’s
relative currency position.

Since 2003, the global
marketplace for coal has experienced swings in the demand/supply
balance. In periods of supply shortfall, as occurred from 2003 to
early 2006 and again in late 2007 through late 2008,
the prices for coal reached record highs in the United States. The increased
worldwide demand was primarily driven by higher prices for oil and natural gas
and economic expansion, particularly in China, India and elsewhere in Asia. At
the same time, infrastructure and regulatory limitations in China contributed to
a tightening of worldwide coal supply, affecting global prices of coal. The
growth in China and India caused an increase in worldwide demand for raw
materials and a disruption of expected coal exports from China to Japan, Korea
and other countries. Since mid-2008, the United States and world
economies have been in an economic recession and financial credit crisis,
significantly reducing the demand for coal.

Metallurgical grade coal
is distinguished by special quality characteristics that include high carbon
content, volatile matter, low expansion pressure, low sulfur content, and
various other chemical attributes. High vol met coal is also high in heat
content (as measured in Btus), and therefore is desirable to utilities as fuel
for electricity generation. Consequently, high vol met coal producers have the
ongoing opportunity to select the market that provides maximum revenue
and profitability. The premium price offered by steel makers for the
metallurgical quality attributes is typically higher than the price offered by
utility coal buyers that value only the heat content. The primary concentration
of United States metallurgical coal reserves is located in the Central
Appalachian region. EVA estimates that the Central Appalachian region supplied
89% of domestic metallurgical coal and 76% of United States exported
metallurgical coal during 2007.

For
utility coal buyers, the primary goal is to maximize heat content, with other
specifications like ash content, sulfur content, and size varying considerably
among different customers. Low sulfur coals, such as those produced in the
western United States and in Central Appalachia, generally demand a higher price
due to restrictions on sulfur emissions imposed by the Federal Clean Air Act, as
amended, and implementing regulations (“Clean Air Act”) and the volatility in
sulfur dioxide (“SO2 “)
allowance prices that occurred in recent years when the demand for all
specifications of coal increased. SO2 allowances
permit utilities to emit a higher level of SO2 than
otherwise required under the Clean Air Act regulations. The demand and premium
price for low sulfur coal is expected to diminish as more utilities install
scrubbers at their coal-fired plants.

Coal
shipped for North American consumption is typically sold at the mine loading
facility with transportation costs being borne by the purchaser. Offshore export
shipments are normally sold at the ship-loading terminal, with the purchaser
paying the ocean freight. According to the National Mining Association (“NMA”),
approximately two-thirds of United States coal shipments in recent years
were transported via railroads. Final delivery to consumers often involves more
than one transportation mode. A significant portion of United States production
is delivered to customers via barges on the inland waterway system and ships
loaded at Great Lakes ports.

Neither
we nor any of our subsidiaries are affiliated with or have any investment in BP,
EIA, EVA, Platts or WCI. We are a member of the NMA.

3

Mining
Methods

We
produce coal using four distinct mining methods: underground room and pillar,
underground longwall, surface and highwall mining, which are explained as
follows:

In the
underground room and pillar method of mining, continuous miners cut three to
nine entries into the coal bed and connect them by driving crosscuts, leaving a
series of rectangular pillars, or columns of coal, to help support the mine roof
and control the flow of air. Generally, openings are driven 20 feet wide and the
pillars are 40 to 100 feet wide. As mining advances, a grid-like pattern of
entries and pillars is formed. When mining advances to the end of a panel,
retreat mining may begin. In retreat mining, as much coal as is feasible is
mined from the pillars that were created in advancing the panel, allowing the
roof to fall upon retreat. When retreat mining is completed to the mouth of the
panel, the mined panel is abandoned.

In
longwall mining (which is a type of underground mining), a shearer (cutting
head) moves back and forth across a panel of coal typically about 1,000 feet in
width, cutting a slice approximately 3.5 feet deep. The cut coal falls onto a
flexible conveyor for removal. Longwall mining is performed under hydraulic roof
supports (shields) that are advanced as the seam is cut. The roof in the mined
out areas falls as the shields advance.

Surface
mining is used to extract coal deposits found close to the surface. This method
involves removal of overburden (earth and rock covering coal) with heavy earth
moving equipment, including large shovels and draglines, and explosives,
followed by extraction of coal from coal seams. After extraction of coal,
disturbed parcels of land are reclaimed by replacing overburden and
reestablishing vegetation and plant life.

Highwall
mining is used in connection with surface mining. A highwall mining system
consists of a remotely controlled continuous miner, which extracts coal and
conveys it via augers or belt conveyors to the portal. The cut is typically a
rectangular, horizontal opening in the highwall (the unexcavated face of exposed
overburden and coal in a surface mine) 11-feet wide and reaching depths of up to
1,000 feet. Multiple, parallel openings are driven into the highwall, separated
by narrow pillars that extend the full depth of the hole.

Use of
continuous miners in the room and pillar method of underground mining
represented approximately 43% of our 2008 coal production. Production from
underground longwall mining operations constituted approximately 3% of our 2008
production. Surface mining represented approximately 47% of our 2008 coal
production. Surface mines also use highwall mining systems to produce coal from
high overburden areas. Highwall mining represented approximately 7% of our 2008
coal production.

Mining
Operations

We
currently have 23 distinct Resource Groups, including seventeen in West
Virginia, five in Kentucky and one in Virginia. These complexes blend, process
and ship coal that is produced from one or more mines, with a single complex
handling the coal production of as many as ten distinct underground or surface
mines. Our mines have been developed at strategic locations in close proximity
to our preparation plants and rail shipping facilities.

We
currently operate solely in the Central Appalachian region, which is the
principal source of low sulfur bituminous coal in the United States, used for
power generation, metallurgical coke production and industrial boilers. Central
Appalachian coal accounted for 20% of 2008 United States coal production
according to EIA.

4

The
following map provides the location of our operations within the Central
Appalachian region:

5

The
following table provides key operational information on our Resource Groups in
2008:

Resource
Group Name

Location
(County)

Active/
Inactive

Mine
Type

Active Mine Count (1)

Mining
Equipment

Transportation

2008 Production (2)

2008 Shipments (3)

Year
Established or Acquired

(Thousands
of Tons)

West
Virgina Resource Groups

Black
Castle

Boone

Active

S

1

HW

truck,
barge

3,110

1,908

1987

Delbarton

Mingo

Active

U

1

NS

527

776

1999

Edwight

Raleigh

Active

S

1

HW

CSX

1,752

-

2003

Elk
Run

Boone

Active

U

5

LW

CSX

2,201

2,796

1978

Endurance

Boone

Active

S

1

HW

CSX

1,127

659

2001

Green
Valley

Nicholas

Active

U

3

CSX

727

641

1996

Guyandotte

Wyoming

Active

U

1

NS

146

110

2006

Independence

Boone

Active

U

3

LW

CSX

1,833

3,420

1994

Inman

Boone

Active

U

1

CSX

280

-

2008

Logan
County

Logan

Active

S/U

9

HW

CSX

4,651

4,458

1998

Mammoth

Kanawha

Active

U

4

barge

1,233

2,616

2004

Marfork

Raleigh

Active

U

8

CSX

4,043

6,881

1993

Nicholas
Energy

Nicholas

Active

S/U

3

HW

NS

3,251

3,081

1997

Progress

Boone

Active

S

1

DL

CSX

5,170

4,177

1998

Rawl

Mingo

Active

U

3

NS

1,000

437

1974

Republic
Energy

Raleigh

Active

S

2

truck

2,617

1,210

2004

Stirrat

Logan

Active

S

1

CSX

1,520

1,463

1993

Kentucky
Resource Groups

Coalgood
Energy

Harlan

Active

S/U

2

HW

CSX

9

-

2005

Long
Fork

Pike

Active

NS

-

1,854

1991

Martin
County

Martin

Active

S/U

4

NS

419

236

1969

New
Ridge

Pike

Active

CSX

-

261

1992

Sidney

Pike

Active

S/U

10

HW

NS

4,950

3,443

1984

Virginia
Resource Group

Knox
Creek

Tazewell

Active

S/U

2

HW

NS

577

536

1997

Total

66

41,143

40,963

__________________________

(1)

Active
mine count as of January 31, 2009.

(2)

For
purposes of this table, coal production has been allocated to the Resource
Group where the coal is mined, rather than the Resource Group where the
coal is processed and shipped. Production amounts above represent coal
extracted from the ground.

(3)

For
purposes of this table, coal shipments have been allocated to the Resource
Group from where the coal is processed and shipped, rather than the
Resource Group where the coal is
mined.

S –
surface mine

U –
underground mine

HW
– highwall miners operated in conjunction with surface
mines

LW –
longwall mine

DL –
dragline

NS –
Norfolk Southern Railway Company

CSX
– CSX Transportation

The
following descriptions of the Resource Groups are current as of January 31,
2009.

West
Virginia Resource Groups

Black Castle. The Black
Castle complex includes a large surface mine, a highwall miner, the Homer III
direct-ship loadout, a stoker plant, and the Omar preparation plant. Some of the
surface mine coal is trucked to the stoker plant where the coal is crushed and
screened. The stoker product is trucked to river docks for barge delivery or
trucked directly to customers. A portion of the coal is trucked to the Omar
plant, where it is crushed and shipped to customers or, if the coal needs
processing, it is belted to the preparation plant at the Independence Resource
Group for processing and shipment. The direct-ship facility at the preparation
plant can crush 500 tons per hour and the preparation plant can process 800 tons
per hour. The Omar preparation plant serves CSX rail system customers with unit
train shipments of up to 110 railcars. Coal is also trucked to the Homer III
loadout where it is crushed and shipped to customers by rail, trucked to river
docks for barge delivery, or trucked directly to customers. The Homer III
loadout serves CSX rail system customers with unit train shipments of up to 100
railcars. The Omar preparation plant was not utilized for processing coal in
2008.

6

Delbarton. The Delbarton
complex includes one underground room and pillar mine and a preparation plant.
Production from the mine is transported to the Delbarton preparation plant via
overland conveyor. The Delbarton preparation plant also processes coal from two
surface mines of the Logan County Resource Group. The Delbarton preparation
plant can process 600 tons per hour. The clean coal product is shipped to
customers via the Norfolk Southern railway in unit trains of up to 110
railcars.

Edwight. The Edwight complex
includes a surface mine, a highwall miner and the Goals preparation plant.
Production from all of the mines is transported via conveyor system to the Goals
preparation plant. The Goals preparation plant can process 800 tons per hour.
The rail loading facility serves CSX railway customers with unit trains of up to
100 railcars.

Elk Run. The Elk Run complex
produces coal from four underground room and pillar mines and the Logans Fork
longwall. All of the room and pillar mines belt coal to the Elk Run preparation
plant, while the longwall belts coal to the preparation plant of the Marfork
Resource Group. Additionally, Elk Run processes coal produced by surface mines
of the Progress Resource Group and transported via underground conveyor system.
The Elk Run preparation plant has a processing capacity of 2,200 tons per hour.
Elk Run also operates a 200 ton per hour stoker facility that produces screened,
small dimension coal for certain of our industrial customers. Customer shipments
are loaded on the CSX rail system in unit trains of up to 150
railcars.

Endurance. The Endurance
complex includes a surface mine, highwall miner and a direct-ship loadout. A
portion of the production from the surface mine is loaded for shipment to
customers at the direct ship loadout and the remainder is trucked to the
preparation plant at the Independence Resource Group for
processing.

Green Valley. The Green
Valley complex includes three underground room and pillar mines and a
preparation plant. The Green Valley preparation plant, which has a processing
capacity of 600 tons per hour, receives coal from the mines via trucks. The rail
loading facility services customers on the CSX rail system with unit train
shipments of up to 75 railcars.

Guyandotte. The Guyandotte
complex includes one underground room and pillar mine. The mine belts coal to a
third-party preparation plant for washing and shipment to customers via the
Norfolk Southern railway system.

Independence. The
Independence complex includes the Revolution longwall mine, two underground room
and pillar mines and a preparation plant. Production from the underground mines
is transported via overland conveyor system to the Independence preparation
plant. The surface mine at the Black Castle Resource Group belts coal and the
surface mine at the Endurance Resource Group trucks coal requiring processing to
the Independence preparation plant . The Independence plant has a processing
capacity of 2,200 tons per hour. Customers are served via rail shipments on the
CSX rail system in unit trains of up to 150 railcars.

Inman. The Inman complex
includes one underground room and pillar mine and a preparation plant.
Production from the underground mine is transported via overland conveyor system
to the preparation plant. The Inman plant has a processing capacity of 800 tons
per hour. Coal processed at the preparation plant is transported via conveyor
belt to Black Castle Resource Group’s Homer III loadout, which serves customers
via rail shipments on the CSX rail system in unit trains of up to 100
railcars.

Logan County. The Logan
County complex includes six surface mines, two highwall miners and three
underground room and pillar mines, plus the Bandmill preparation plant and the
Feats loadout, all on the CSX rail system. Four surface mines deliver coal to
the Bandmill plant via truck and conveyor system, two surface mines truck coal
to Edwight Resource Group’s Goals preparation plant, and the underground mines
belt coal directly to the Bandmill plant. The Feats loadout can service
customers via the CSX rail system with unit train shipments of up to 80 cars.
The Bandmill preparation plant has a processing capacity of 1,800 tons per hour.
The Bandmill rail loading facility services customers via the CSX rail system
with unit train shipments of up to 150 railcars.

Mammoth. The Mammoth complex
operates four underground room and pillar mines and a preparation plant. Coal is
transported to the preparation plant using a conveyor system. The plant has a
1,200 tons per hour processing facility capacity with barge loading capabilities
on the upper Kanawha River and a rail loading facility that services customers
on the Norfolk Southern railway with unit trains of up to 130
railcars.

Marfork. The Marfork complex
includes eight underground room and pillar mines and a preparation plant.
Production from one of the mines is trucked and from five of the mines is belted
directly to the Marfork preparation plant while production from the remaining
two mines is belted to Edwight Resource Group’s Goals preparation plant. The
Marfork preparation plant has a capacity of 2,400 tons per hour. Customers are
served via the CSX rail system with unit trains of up to 150
railcars.

7

Nicholas Energy. The Nicholas
Energy complex includes one underground room and pillar mine, two surface mines,
two highwall miners and a preparation plant. Coal from the underground mine is
transported to the preparation plant for processing via conveyor system. Coal
from the highwall miners and the portion of surface mined coal requiring
processing is transported to the preparation plant using off-road trucks.
Coal not requiring processing is transported via off-road trucks to a conveyor
system that moves the coal directly to a rail loadout facility. The plant has a
processing capacity of 1,200 tons per hour. Coal shipments are loaded into rail
cars for delivery via the Norfolk Southern railway in unit trains of up to 140
railcars, or are transported via on-highway trucks to the Mammoth Resource
Group’s barge loading facility.

Progress. The Progress
complex includes the large Twilight MTR surface mine. A dragline is also
utilized at the Twilight MTR surface mine. Production from the Twilight MTR
surface mine is transported via underground conveyor to the Elk Run Resource
Group for processing and rail shipment.

Rawl. The Rawl complex
includes three underground room and pillar mines and a preparation plant.
Production from the mines is transported via truck to the preparation plant of
the Stirrat Resource Group. The Rawl plant, which was idled in December 2006,
has a throughput capacity of 1,450 tons per hour. Customers can be served by the
Rawl plant via the Norfolk Southern railway with unit trains of up to 150
railcars.

Republic Energy. The Republic
Energy complex consists of two surface mines. Direct-ship coal is trucked using
on-highway trucks to various docks on the Kanawha River for barge delivery to
customers and to the Marfork Resource Group for rail delivery to
customers. Coal requiring processing is trucked using on-highway
trucks to Mammoth Resource Group’s preparation plant for processing and barge or
train delivery to customers.

Stirrat. The Stirrat complex
includes one surface mine, a preparation plant and the Superior loadout. The
surface mine trucks coal directly to two 12,500 ton silos at the Superior
loadout. The Superior loadout serves CSX railway customers with unit trains of
up to 100 railcars. The Stirrat preparation plant cleans coal from three
adjacent underground room and pillar mines of the Rawl Resource Group. The plant
has a rated capacity of 600 tons per hour. Customers are served via the CSX rail
system with unit trains of up to 100 railcars.

Kentucky
Resource Groups

Coalgood Energy. The Coalgood
Energy complex includes one underground room and pillar mine, one surface mine,
one highwall miner and a direct-ship loadout. The coal from the surface mine is
trucked off-road to the loadout, which serves CSX railway customers with unit
trains of up to 100 railcars. The production from the underground
mine is being stockpiled until construction is completed on an 800 tons per hour
preparation plant, which is projected to be in service by April
2009. Coal from this preparation plant will be loaded onto trains
from the existing loadout.

Long Fork. The Long Fork
preparation plant processes coal produced by two underground room and pillar
mines of the Sidney Resource Group. All production is transported via conveyor
system to the Long Fork preparation plant for processing and shipping to
customers. The Long Fork plant has a rated capacity of 1,500 tons per hour. The
rail loading facility services customers on the Norfolk Southern railway with
unit trains of up to 150 railcars.

Martin County. The Martin
County complex includes two underground room and pillar mine, two surface mines
and a preparation plant. Direct-ship coal production from the surface
mines is shipped to river docks via truck. Surface mine coal requiring
processing and production from the underground mines is transported by conveyor
belt or truck to the preparation plant. Martin County’s preparation plant has a
throughput capacity of 1,500 tons per hour, although the throughput capacity is
limited due to decreased impoundment availability. The coal from the preparation
plant can be shipped either via the Norfolk Southern railway in unit trains of
up to 125 railcars or to river docks via truck.

New Ridge. The New Ridge
complex loads clean coal that is transported via truck from the preparation
plant of the Sidney Resource Group and coal trucked directly from Sidney’s
surface mine. The New Ridge preparation plant has a capacity of 800 tons per
hour. The preparation plant is currently idle but may be reactivated from time
to time during 2009 as needed. All coal is loaded for shipment to customers via
the CSX rail system in unit trains of up to 100 railcars.

Sidney. The Sidney complex includes nine
underground room and pillar mines, one surface mine, a highwall miner and a
preparation plant. Two of the underground mines transport coal via underground
conveyor system to the Long Fork Resource Group for processing and shipment, and
the remainder of the underground mines transport production via underground
conveyor system or truck to Sidney’s preparation plant. A portion of the coal
from Sidney’s preparation plant and coal from the surface mines are trucked to
the New Ridge Resource Group for loading into railroad cars. Sidney’s
preparation plant has a capacity of 1,500 tons per hour. The rail loading
facility at the preparation plant serves customers on the Norfolk Southern rail
system with unit trains of up to 140 railcars.

8

Virginia
Resource Group

Knox Creek. The Knox Creek
complex includes one underground room and pillar mine, one surface mine, two
highwall miners and a preparation plant. Production from the underground mine is
belted by conveyor system to the preparation plant, while coal requiring
processing from the surface mine is trucked to the preparation plant. The
preparation plant has a feed capacity of 650 tons per hour. The preparation
plant serves customers on the Norfolk Southern rail system with unit trains of
up to 100 railcars.

Coal
Reserves

We
estimate that, as of December 31, 2008, we had total recoverable reserves of
approximately 2.3 billion tons consisting of both proven and probable reserves.
“Reserves” are defined by the SEC Industry Guide 7 as that part of a mineral
deposit, which could be economically and legally extracted or produced at the
time of the reserve determination. “Recoverable” reserves means coal that is
economically recoverable using existing equipment and methods under federal and
state laws currently in effect. Approximately 1.5 billion tons of reserves are
classified as proven reserves. “Proven (measured) reserves” are defined by the
SEC Industry Guide 7 as reserves for which (a) quantity is computed from
dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or
quality are computed from the results of detailed sampling and (b) the sites for
inspection, sampling and measurement are spaced so closely and the geologic
character is so well defined that size, shape, depth and mineral content of
reserves are well-established. The remaining approximately 0.8 billion tons of
our reserves are classified as probable reserves. “Probable reserves” are
defined by the SEC Industry Guide 7 as reserves for which quantity and grade
and/or quality are computed from information similar to that used for proven
(measured) reserves, but the sites for inspection, sampling, and measurement are
farther apart or are otherwise less adequately spaced. The degree of assurance,
although lower than that for proven (measured) reserves, is high enough to
assume continuity between points of observation.

Information
about our reserves consists of estimates based on engineering, economic and
geological data assembled and analyzed by our internal engineers, geologists and
finance associates. Reserve estimates are updated annually using geologic data
taken from drill holes, adjacent mine workings, outcrop prospect openings and
other sources. Coal tonnages are categorized according to coal quality, seam
thickness, mineability and location relative to existing mines and
infrastructure. In accordance with applicable industry standards, proven
reserves are those for which reliable data points are spaced no more than 2,700
feet apart. Probable reserves are those for which reliable data points are
spaced 2,700 feet to 7,900 feet apart. Further scrutiny is applied using
geological criteria and other factors related to profitable extraction of the
coal. These criteria include seam height, roof and floor conditions, yield and
marketability.

As with
most coal-producing companies in Central Appalachia, the majority of our coal
reserves are controlled pursuant to leases from third-party landowners. The
leases are generally long-term in nature (original term five to fifty years or
until the mineable and merchantable coal reserves are exhausted), and
substantially all of the leases contain provisions that allow for automatic
extension of the lease term as long as mining continues. These leases convey
mining rights to the coal producer in exchange for a per ton or percentage of
gross sales price royalty payment to the lessor. However, approximately 17% of
our reserve holdings are owned and require no royalty or per ton payment to
other parties. Royalty expense for coal reserves from our producing properties
(owned and leased) was approximately 4.4% of Produced coal revenue for the year
ended December 31, 2008.

9

hss

The
following table provides proven and probable reserve data by “status” (i.e.,
location, owned or leased, assigned or unassigned, etc.) as of December 31,
2008:

Recoverable Reserves (1)

Resource
Group

Location (2)

Total

Proven

Probable

Assigned (3)

Unassigned (3)

Owned

Leased

(In
Thousands of Tons)

West
Virginia

Black Castle

Boone
County

86,132

59,402

26,730

39,362

46,770

538

85,594

Delbarton

Mingo
County

286,237

120,440

165,797

140,739

145,498

25

286,212

Edwight

Raleigh
County

7,796

7,796

-

7,796

-

-

7,796

Elk
Run

Boone
County

108,782

75,615

33,167

59,488

49,294

4,660

104,122

Endurance

Boone
County

23,007

23,007

-

23,007

-

22,602

405

Green Valley

Nicholas
County

9,973

9,973

-

9,973

-

-

9,973

Guyandotte

Wyoming
County

45,564

17,366

28,198

2,100

43,464

330

45,234

Independence

Boone
County

44,466

43,156

1,310

31,487

12,979

9,482

34,984

Inman

Boone
County

49,473

47,958

1,515

17,066

32,407

-

49,473

Logan County

Logan
County

72,805

65,721

7,084

55,081

17,724

2,388

70,417

Mammoth

Kanawha
County

86,425

66,086

20,339

73,108

13,317

42,421

44,004

Marfork

Raleigh
County

133,399

105,262

28,137

74,976

58,423

815

132,584

Nicholas
Energy

Nicholas
County

88,795

48,186

40,609

46,379

42,416

35,517

53,278

Progress

Boone
County

17,262

17,262

-

17,262

-

-

17,262

Rawl

Mingo
County

108,849

81,087

27,762

74,852

33,997

1,333

107,516

Republic
Energy

Raleigh
County

56,208

49,688

6,520

56,208

-

-

56,208

Stirrat

Logan
County

11,745

7,778

3,967

5,078

6,667

-

11,745

Kentucky

Coalgood
Energy

Harlan
County

21,261

12,357

8,904

-

21,261

2,704

18,557

Long
Fork

Pike
County

4,964

2,764

2,200

264

4,700

-

4,964

Martin County

Martin
County

48,181

31,492

16,689

2,783

45,398

1,336

46,845

New
Ridge

Pike
County

-

-

-

-

-

-

-

Sidney

Pike
County

124,211

70,173

54,038

124,211

-

7,028

117,183

Virginia

Knox
Creek

Tazewell
County

60,675

44,586

16,089

32,605

28,070

4,552

56,123

Subtotal

1,496,210

1,007,155

489,055

893,825

602,385

135,731

1,360,479

Land Management Companies: (4)

Black
King

Boone
County, WV

53,144

40,762

12,382

734

52,410

-

53,144

Raleigh
County, WV

Boone
East

Boone
County, WV

141,976

102,853

39,123

5,169

136,807

63,547

78,429

Kanawha
County, WV

Boone
West

Lincoln
County, WV

242,308

92,201

150,107

10,496

231,812

65,553

176,755

Logan
County, WV

Ceres Land

Raleigh
County, WV

33,351

24,220

9,131

-

33,351

-

33,351

Rostraver Energy (5)

Various
counties, PA

94,086

44,449

49,637

-

94,086

79,907

14,179

Lauren
Land

Mingo
County, WV

167,671

107,301

60,370

11,175

156,496

18,011

149,660

Logan
County, WV

Various
counties, KY

New
Market Land

Wyoming
County, WV

5,884

2,690

3,194

-

5,884

102

5,782

Raven
Resources

Raleigh
County, WV

18,978

18,978

-

-

18,978

-

18,978

Boone
County, WV

Tennessee
Consolidated Coal

Various
counties, TN

26,907

1,332

25,575

-

26,907

24,054

2,853

Subtotal
Land Management

784,305

434,786

349,519

27,574

756,731

251,174

533,131

Other

N/A

57,733

29,680

28,053

12,740

44,993

3,112

54,621

Total

2,338,248

1,471,621

866,627

934,139

1,404,109

390,017

1,948,231

__________________________

(1)

Recoverable
reserves represent the amount of proven and probable reserves that can
actually be recovered from the reserve base taking into account all mining
and preparation losses involved in producing a saleable product using
existing methods under current law.

(2)

All
of the recoverable reserves listed are in Central Appalachia, except for
the Rostraver reserves, which are located in Northern Appalachia and
Lauren Land reserves, a portion of which are located in the Illinois
Basin. The reserve numbers of each Resource Group contain a moisture
factor specific to the particular reserves of that Resource Group. The
moisture factor represents the average moisture present in our delivered
coal.

(3)

Assigned
Reserves represent recoverable reserves that are dedicated to a specific
permitted mine; otherwise, the reserves are considered Unassigned. For
Land Management Companies, Assigned Reserves have been leased to a
third-party and are dedicated to a specific permitted mine of the
lessee.

(4)

Land
management companies are our subsidiaries whose primary purposes are to
acquire and hold our reserves.

(5)

Previously
known as Duncan Fork.

10

The
categorization of the “quality” (i.e., sulfur content, Btu, coal type,
etc.) of coal reserves is as
follows:

Recoverable Reserves (1)

Recoverable

Sulfur
Content

Avg.
Btu as

Resource
Group

Reserves

+1% (2)

-1% (2)

Compliance (2)

Received (3)

Coal Type (4)

(In
Thousands of Tons Except Average Btu as Received)

West
Virginia

Black Castle

86,132

34,116

52,016

22,167

12,700

Utility
and Industrial

Delbarton

286,237

111,954

174,283

127,073

13,350

High
Vol Met, Utility, and Industrial

Edwight

7,796

1,622

6,174

5,987

12,550

High
Vol Met, Utility, and Industrial

Elk
Run

108,782

47,027

61,755

51,407

13,700

High
Vol Met, Utility, and Industrial

Endurance

23,007

4,952

18,055

10,047

11,850

Utility
and Industrial

Green Valley

9,973

471

9,502

3,853

13,100

High
Vol Met, Utility, and Industrial

Guyandotte

45,564

-

45,564

45,564

13,850

Low
Vol Met

Independence

44,466

19,425

25,041

-

12,650

High
Vol Met, Utility, and Industrial

Inman

49,473

32,667

16,806

16,895

12,650

High
Vol Met and Utility

Logan County

72,805

22,346

50,459

39,009

12,050

High
Vol Met, Utility, and Industrial

Mammoth

86,425

5,216

81,209

41,706

12,150

Utility
and Industrial

Marfork

133,399

41,679

91,720

34,931

14,050

High
Vol Met, Utility, and Industrial

Nicholas
Energy

88,795

39,959

48,836

24,705

12,450

Utility
and Industrial

Progress

17,262

6,021

11,241

11,241

12,350

High
Vol Met, Utility, and Industrial

Rawl

108,849

28,061

80,788

59,614

12,350

High
Vol Met, Utility, and Industrial

Republic

56,208

11,014

45,194

31,238

12,450

High
Vol Met and Utility

Stirrat

11,745

223

11,522

7,663

12,300

High
Vol Met, Utility, and Industrial

Kentucky

Coalgood
Energy

21,261

4,712

16,549

11,680

13,100

High
Vol Met, Utility, and Industrial

Long
Fork

4,964

3,500

1,464

-

12,850

Utility
and Industrial

Martin County

48,181

33,900

14,281

5,120

12,500

Utility
and Industrial

New
Ridge

-

-

-

-

-

N/A

Sidney

124,211

47,878

76,333

52,545

13,200

High
Vol Met, Utility, and Industrial

Virginia

Knox
Creek

60,675

7,022

53,653

40,250

12,350

High
Vol Met, Utility, and Industrial

Subtotal

1,496,210

503,765

992,445

642,695

Land Management Companies: (5)

Black
King

53,144

99

53,045

36,508

12,150

High
Vol Met and Utility

Boone
East

141,976

34,939

107,037

36,789

12,500

High
Vol Met, Utility, and Low Vol Met

Boone
West

242,308

130,063

112,245

79,369

13,350

High
Vol Met and Utility

Ceres Land

33,351

5,991

27,360

12,740

12,700

High
Vol Met and Utility

Rostraver Energy
(6)

94,086

94,086

-

-

14,050

High
Vol Met, Utility, and Industrial

Lauren
Land

167,671

85,346

82,325

62,628

12,700

High
Vol Met and Utility

New
Market Land

5,884

-

5,884

5,884

12,700

High
Vol Met and Low Vol Met

Raven
Resources

18,978

7,449

11,529

1,369

12,100

High
Vol Met and Utility

Tennessee
Consolidated Coal

26,907

20,353

6,554

4,816

13,000

High
Vol Met, Utility and Industrial

Subtotal
Land Management

784,305

378,326

405,979

240,103

Other

57,733

6,638

51,095

45,947

12,800

Various

Total

2,338,248

888,729

1,449,519

928,745

__________________________

(1)

The
reserve numbers of each Resource Group contain a moisture factor specific
to the particular reserves of that Resource Group. The moisture factor
represents the average moisture present in our delivered
coal.

(2)

+1%
or -1% refers to sulfur content as a percentage in coal by weight.
Compliance coal is less than 1% sulfur content by weight and is included
in the -1% column.

(3)

Represents
an estimate of the average Btu per pound present in our coal, as it is
received by the customer.

(4)

Reserve
holdings include metallurgical coal reserves. Although these metallurgical
coal reserves receive the highest selling price in the current coal market
when marketed to steel-making customers, they can also be marketed as an
ultra high Btu, low sulfur utility coal for electricity
generation.

(5)

Land
management companies are our subsidiaries whose primary purposes are to
acquire and hold our reserves.

(6)

Previously
known as Duncan Fork.

11

Compliance
compared to non-compliance coal

Coals are
sometimes characterized as compliance or non-compliance coal. The phrase
compliance coal, as it is commonly used in the coal industry, refers to
compliance only with sulfur dioxide emissions standards imposed by Title IV of
the Clean Air Act and indicates that when burned, the coal will produce
emissions that will meet the current standard without further cleanup. A coal
that is considered a compliance coal for meeting sulfur dioxide standards may
not meet an emission standard for a different pollutant such as mercury.
Moreover, the term compliance coal is always used with reference to the then
current regulatory limit. Clean air regulations that further restrict sulfur
dioxide emissions will likely reduce significantly the amount of coal that can
be labeled compliance. Currently, coal classified as compliance will meet the
power plant emission standard of 1.2 pounds of sulfur dioxide per million Btu’s
of fuel consumed. At December 31, 2008, approximately 0.9 billion tons, or 40%,
of our coal reserves met the current standard as compliance coal.

Our 2008
shipments of 41.0 million tons were loaded from 23 mining complexes. Rail
shipments constituted 91% of total shipments, with 26% loaded on Norfolk
Southern trains and 65% loaded on CSX trains. The balance was shipped from
mining complexes via truck or barge.

Approximately
22% of production was ultimately delivered via the inland waterway system. Coal
is loaded directly into barges, or is transported by rail or truck to docks on
the Ohio, Big Sandy and Kanawha Rivers and then ultimately transported by barge
to electric utilities, integrated steel producers and industrial consumers
served by the inland waterway system. We also moved approximately 2% of our
production to Great Lakes’ ports for transport to various United States and
Canadian customers.

Customers
and Coal Contracts

We have
coal supply commitments with a wide range of electric utilities, steel
manufacturers, industrial customers and energy traders and brokers. By offering
coal of both steam and metallurgical grades, we are able to serve a diverse
customer base. This market diversity allows us to adjust to changing market conditions and
sustain high sales volumes. The majority of our customers purchase coal for
terms of one year or longer, but we also supply coal on a spot basis for some
customers. At
December 31, 2008, approximately 75%, 13% and 12% of Trade receivables
represents amounts due from utility customers, metallurgical customers and
industrial customers, respectively, compared with 56%, 28% and 16%,
respectively, as of December 31, 2007. During 2008, we had 25 separate,
active agreements with our largest customer, Constellation Energy Commodities
Group, Inc. (“Constellation”), with terms ranging from one month to two years
which, in the aggregate accounted for 11% of our fiscal year 2008 Produced coal
revenue. The largest of the 25 agreements represented less than 2% of our fiscal
year 2008 Produced coal revenue. As a result, we do not consider our business to
be substantially dependent upon any of these agreements, individually or
in the aggregate. No other customer accounted for 10% or more of fiscal year
2008 Produced coal revenue or produced tons. For fiscal year 2009, our
contracted sales under separate agreements to Constellation currently represent
approximately 26% of our projected produced coal tonnage and 18% of our
projected Produced coal revenue. There are no other customers to whom we expect
to sell 10% or more of produced tons or to account for 10% or more of
Produced coal revenue in 2009.

As is
customary in the coal industry, we enter into long-term contracts (one year or
more in duration) with many of our customers. These arrangements allow customers
to secure a supply for their future needs and provide us with greater
predictability of sales volume and sales prices. Long-term contracts are a
result of extensive negotiations with customers. As a result, the terms of these
contracts vary with respect to price adjustment mechanisms, pricing terms,
permitted sources of supply, force majeure provisions, quality adjustments and
other parameters. Some of the contracts contain price adjustment mechanisms that
allow for changes to prices based on statistics from the United States
Department of Labor. Coal quality specifications may be especially stringent for
steel customers.

For the
year ended December 31, 2008, approximately 97% of coal sales volume was
pursuant to long-term contracts. We anticipate that in 2009, coal sales volume
percentage pursuant to long-term arrangements will be comparable to 2008. As of
February 19, 2009, we had contractual sales commitments of approximately 101
million tons, including commitments subject to price reopener and/or optional
tonnage provisions. Remaining contractual terms of our sales commitments range
from one to eleven years with an average volume-weighted remaining term of
approximately 3.1 years. Sixty-five percent of our total contracted sales tons
are priced. As of February 19, 2009, we have committed most of our expected 2009
production. In addition, we purchase coal from third-party coal producers from
time to time to supplement production and resell this coal to
customers.

12

Suppliers

The main types of goods we purchase are
mining equipment and replacement parts, explosives, fuel, tires, steel-related
(including roof control) products and lubricants. Although we have many
well-established, strategic relationships with our key suppliers, we do not
believe that we are dependent on any of our individual suppliers, except as
noted below. The supplier base providing mining materials has been relatively
consistent in recent years, although there continues to be some consolidation.
Consolidation of suppliers of explosives has limited the number of sources for
these materials. Although our current supply of explosives is concentrated with
one supplier, some alternative sources are available to us in the regions where
we operate. Further consolidation of underground equipment suppliers has
resulted in a situation where purchases of certain underground mining equipment
are concentrated with one principal supplier; however, supplier competition
continues to develop. In recent years, demand for certain surface and
underground mining equipment and off-the-road tires has increased. As a result,
lead times for certain items have generally increased, although no material
impact is currently expected to our cash flows, results of operations or
financial condition.

Competition

The coal
industry in the United States and overseas is highly competitive, with numerous
producers selling into all markets that use coal. We compete against large and
small producers in the United States and overseas. The NMA estimated that
in 2007 there were 25 coal companies in the United States with annual production
of 5 million or more tons, which together account for approximately 85% of
United States production. According to the EIA, we were the sixth largest coal
company in terms of tons produced in 2007, exceeded by Peabody Energy
Corporation (“Peabody”), Rio Tinto Energy America, Inc., Arch Coal, Inc.
(“Arch”), Foundation Coal Holdings Inc. (“Foundation”) and CONSOL Energy Inc.
(“CONSOL”). However, in terms of produced coal revenue in 2007, EVA ranks
us as the fourth largest United States coal company, exceeded by only
Peabody, CONSOL and Arch.

We
compete with other producers primarily on the basis of price, coal quality,
transportation cost and reliability of supply. Continued demand for coal is also
dependent on factors outside of our control, including demand for electricity
and steel, general economic conditions, environmental and governmental
regulations, weather, technological developments, and the availability and cost
of alternative fuel sources. We sell coal to foreign electricity generators and
to the more specialized metallurgical coal market, both of which are
significantly affected by international demand and competition.

Historically,
global coal markets have responded to increased demand and higher prices for
coal by increasing production and supply. In recent years, however, capacity
expansion has been somewhat limited by the increased costs of mining, high
capital requirements, coal seam degradation, reserve depletion, labor shortages,
transportation issues related to rail, barge and truck shipments, higher costs
related to compliance with new and increasingly stringent regulations, the
difficulty of obtaining permits and bonding and other factors. While these
constraints persist in major coal producing countries and regions, periods of
supply and demand imbalance may be extended and increased pricing volatility may
result.

Other
Related Operations

We have
other related operations and activities in addition to our normal coal
production and sales business. The following business activities are included in
this category:

Coal Handling Joint Venture.
We hold a 50% interest in a joint venture that owns and operates third-party
end-user coal handling facilities. Certain of our subsidiaries currently operate
the coal handling facilities for the joint venture.

Gas Operations. We hold
interests in operations that produce, gather and market natural gas from shallow
reservoirs in the Appalachian Basin. In the eastern United States, conventional
natural gas reservoirs are located in various types of sedimentary formations at
depths ranging from 2,000 to 15,000 feet. The depths of the reservoirs drilled
and operated by us range from 2,500 to 5,800 feet.

Nearly
all of our gas production is from operations in southern West Virginia. In this
region, we own and operate approximately 160 wells, 200 miles of gathering line,
and various small compression facilities. Our southern West Virginia operations
control approximately 27,000 acres of drilling rights. In addition, we own a
majority working interest in 50 wells operated by others, and minority
working interests in approximately 13 wells operated by others. The
December 2008 average daily production, from the 228 wells owned or
controlled, was 2.0 million cubic feet per day. We do not consider our current
gas production level, revenues or costs to be material to our cash flows,
results of operations or financial condition.

13

Other. From time to time, we
also engage in the sale of certain non-strategic assets such as timber, oil and
gas rights, surface properties and reserves. In addition, we have established
several contractual arrangements with customers where services other than coal
supply are provided on an ongoing basis. None of these contractual arrangements
is considered to be material. Examples of such other services include
arrangements with several metallurgical and industrial customers to coordinate
shipment of coal to their stockpiles, maintain ownership of the coal inventory
on their property and sell tonnage to them as it is consumed. We work closely
with customers to provide other services in response to the current needs of
each individual customer.

Marketing
and Sales

Our
marketing and sales force, based in the corporate office in Richmond, Virginia,
includes sales managers, distribution/traffic managers and administrative
personnel.

During
the year ended December 31, 2008, we sold 41.0 million tons of produced coal for
total Produced coal revenue of $2.6 billion. The breakdown of produced tons sold
by market served was 66% utility, 24% metallurgical and 10% industrial. Sales
were concluded with over 100 customers. Export shipment revenue totaled
approximately $756.3 million, representing approximately 30% of 2008
Produced coal revenue. In 2008, we exported shipments to customers in 17
countries across the globe, which included destinations in Europe, Asia, Africa,
South America and North America. Sales are made in United States dollars, which
minimizes foreign currency risk.

Employees
and Labor Relations

As of
December 31, 2008, we had 6,743 employees, including 124 employees affiliated
with the United Mine Workers of America (“UMWA”). Relations with employees are
generally good, and there have been no material work stoppages in the past ten
years.

Environmental,
Safety and Health Laws and Regulations

The coal
mining industry is subject to regulation by federal, state and local authorities
on matters such as the discharge of materials into the environment, employee
health and safety, permitting and other licensing requirements, reclamation and
restoration of mining properties after mining is completed, management of
materials generated by mining operations, surface subsidence from underground
mining, water pollution, water appropriation and legislatively mandated benefits
for current and retired coal miners, air quality standards, protection of
wetlands, endangered plant and wildlife protection, limitations on land use, and
storage of petroleum products and substances that are regarded as hazardous
under applicable laws. The possibility exists that new legislation or
regulations may be adopted that could have a significant impact on our mining
operations or on our customers’ ability to use coal.

Numerous
governmental permits and approvals are required for mining operations.
Regulations provide that a mining permit or modification can be delayed, refused
or revoked if an officer, director or a stockholder with a 10% or greater
interest in the entity is affiliated with or is in a position to control another
entity that has outstanding permit violations. Thus, past or ongoing violations
of federal and state mining laws by individuals or companies no longer
affiliated with us could provide a basis to revoke existing permits and to deny
the issuance of addition permits. We are required to prepare and present to
federal, state or local authorities data and/or analysis pertaining to the
effect or impact that any proposed exploration for or production of coal may
have upon the environment, public and employee health and safety. All
requirements imposed by such authorities may be costly and time-consuming and
may delay commencement or continuation of exploration or production operations.
Accordingly, the permits we need for our mining and gas operations may not be
issued, or, if issued, may not be issued in a timely fashion. Permits we need
may involve requirements that may be changed or interpreted in a manner that
restricts our ability to conduct our mining operations or to do so profitably.
Future legislation and administrative regulations may increasingly emphasize the
protection of the environment, health and safety and, as a consequence, our
activities may be more closely regulated. Such legislation and regulations, as
well as future interpretations of existing laws, may require substantial
increases in equipment and operating costs, delays, interruptions or a
termination of operations, the extent of which cannot be predicted.

14

While it
is not possible to quantify the expenditures we incur to maintain compliance
with all applicable federal and state laws, those costs have been and are
expected to continue to be significant. We post surety performance bonds or
letters of credit pursuant to federal and state mining laws and regulations for
the estimated costs of reclamation and mine closing, often including the cost of
treating mine water discharge when necessary. Compliance with these laws has
substantially increased the cost of coal mining for all domestic coal producers.
We endeavor to conduct our mining operations in compliance with all applicable
federal, state and local laws and regulations. However, even with our
substantial efforts to comply with extensive and comprehensive regulatory
requirements, violations during mining operations occur from time to time. In
2007, EPA filed suit against us and twenty-seven of our subsidiaries alleging
violations of the Federal Clean Water Act. In January 2008, we announced that we
had agreed with EPA to settle the lawsuit for a payment of $20 million in
penalties. In 2008, we spent approximately $16.2 million to comply with
environmental laws and regulations, of which $7.8 million was for reclamation,
including $5.0 million for final reclamation. None of these expenditures were
capitalized. We anticipate spending approximately $42.8 million and $34.8
million in such non-capital expenditures in 2009 and 2010, respectively. Of
these expenditures, $31.4 million and $23.1 million for 2009 and 2010,
respectively, are anticipated to be for final reclamation.

Emission Control Technology.
We own a majority interest in Coalsolv, LLC (“Coalsolv”), which holds the United
States marketing rights for the coal-fired plant emission control technologies
developed by Cansolv Technologies, Inc. (“Cansolv”). Cansolv’s technologies
remove sulfur dioxide (SO2), nitrogen
oxide (NOx), mercury,
carbon dioxide (CO2), and
other greenhouse gases from flue gas emissions. The Cansolv process has been
utilized at various industrial facilities around the world, with additional
projects underway in China and Canada. Through Coalsolv, we contributed funds
for a pilot plant that has been utilized in the United States and Canada for the
testing and piloting of the Cansolv SO2, NOX, mercury,
and CO2 capture
technology on coal-fired power plants.

Mine
Safety and Health

Stringent
health and safety standards have been in effect since Congress enacted the
Federal Coal Mine Health and Safety Act of 1969. The Federal Coal Mine Safety
and Health Act of 1977 significantly expanded the enforcement of safety and
health standards and imposed safety and health standards on all aspects of
mining operations. A further expansion occurred in June 2006 with the enactment
of the Mine Improvement and New Emergency Response Act of 2006 (“MINER
Act”).

The MINER
Act and related Mine Safety and Health Administration (“MSHA”) regulatory action
require, among other things, improved emergency response capability, increased
availability of emergency breathable air, enhanced communication and tracking
systems, more available mine rescue teams, increased mine seal strength and
monitoring of sealed areas in underground mines, as well as larger penalties by
MSHA for noncompliance by mine operators. Coal producing states, including West
Virginia and Kentucky, passed similar legislation. The bituminous coal mining
industry was actively engaged throughout 2008 in activities to achieve
compliance with these new requirements. These compliance efforts will continue
into 2009.

In
2008, MSHA published final rules implementing Section 4 of the MINER Act that
addressed mine rescue, sealing of abandoned areas, refuge alternatives, fire
prevention and detection, use of air from the belt entry and civil penalty
assessments. MSHA also provided guidance on wireless communication
and electronic tracking systems and new requirements for the plugging of coal
bed methane wells with horizontal branches in coal seams. Two
additional regulations were also published related to measures to achieve
alcohol and drug free mines and the use of coal mine dust personal monitors. In
February 2009, the United States Court of Appeals for the District of Columbia
Circuit held that the 2008 rules were not sufficient to satisfy the requirements
of the Miner Act in certain respects, and remanded those portions of the rules
to MSHA for reconsideration. New rules issued by the MSHA will likely contain
more stringent provisions regarding training of rescue teams.

All of
the states in which we operate have state programs for mine safety and health
regulation and enforcement. Collectively, federal and state safety and health
regulation in the coal mining industry is perhaps the most comprehensive and
pervasive system for protection of employee health and safety affecting any
segment of industry in the United States. While regulation has a significant
effect on our operating costs, our United States competitors are subject to the
same regulation.

We
measure our success in this area primarily through the use of occupational
injury and illness frequency rates. We believe that a superior safety and health
regime is inherently tied to achieving productivity and financial goals, with
overarching benefits for our shareholders, the community and the
environment.

Black Lung. Under federal
black lung benefits legislation, each coal mine operator is required to make
payments of black lung benefits or contributions to: (i) current and former coal
miners totally disabled from black lung disease; and (ii) certain survivors of a
miner who dies from black lung disease. The Black Lung Disability Trust Fund, to
which we must make certain tax payments based on tonnage sold, provides for the
payment of medical expenses to claimants whose last mine employment was before
January 1, 1970 and to claimants employed after such date, where no responsible
coal mine operator has been identified for claims or where the responsible coal
mine operator has defaulted on the payment of such benefits. In addition to
federal acts, we are also liable under various state statutes for black lung
claims. Federal benefits are offset by any state benefits paid.

15

Workers’ Compensation. We are
liable for workers’ compensation benefits for traumatic injuries under state
workers’ compensation laws in the states in which we have operations. Workers’
compensation laws are administered by state agencies with each state having its
own set of rules and regulations regarding compensation owed to an employee
injured in the course of employment.

Coal Industry Retiree
Health Benefit Act of 1992 and Tax Relief and Retiree Health Care Act of
2006. The Coal Industry Retiree Health Benefit Act of 1992 (“Coal Act”)
provides for the funding of health benefits for certain UMWA retirees. The Coal
Act established the Combined Benefit Fund (“CBF”) into which “signatory
operators” and “related persons” are obligated to pay annual premiums for
covered beneficiaries. The Coal Act also created a second benefit fund, the 1992
Benefit Plan, for miners who retired between July 21, 1992 and September 30,
1994 and whose former employers are no longer in business. On December 20, 2006,
President Bush signed the Tax Relief and Retiree Health Care Act of 2006. This
legislation includes important changes to the Coal Act that impacts all
companies required to contribute to the CBF. Effective October 1, 2007, the SSA
revoked all beneficiary assignments made to companies that did not sign a 1988
UMWA contract (“reachback companies”), but phased-in their premium relief. As a
pre-1988 signatory, Massey related reachback companies received the applicable
premium relief. Effective October 1, 2007, reachback companies will pay only 55%
of their plan year 2008 assessed premiums, 40% of their plan year 2009 assessed
premiums, and 15% of their plan year 2010 assessed premiums. General United
States Treasury money will be transferred to the CBF to make up the difference.
After 2010, reachback companies will have no further obligations to the CBF, and
transfers from the United States Treasury will cover all of the health care
costs for retirees and dependents previously assigned to reachback
companies.

Pension Protection Act. The
Pension Protection Act of 2006 (“Pension Act”) has simplified and transformed
the rules governing the funding of defined benefit plans, accelerated funding
obligations of employers, made permanent certain provisions of the Economic
Growth and Tax Relief Reconciliation Act of 2001, made permanent the
diversification rights and investment education provisions for plan participants
and encouraged automatic enrollment in defined contribution 401(k) plans.
In general, most provisions of the Pension Act took effect for plan years
beginning on or after December 31, 2007. Plans generally are required to
set a funding target of 100% of the present value of accrued benefits and
sponsors are required to amortize unfunded liabilities over a 7-year period. The
Pension Act included a funding target phase-in provision consisting of a 92%
funding target in 2008, 94% in 2009, 96% in 2010, and 100% thereafter. Plans
with a funded ratio of less than 80%, or less than 70% using special
assumptions, are deemed to be “at risk” and are subject to additional funding
requirements. As of December 31, 2008, our pension plan was underfunded by $63
million. We currently expect to make contributions in 2009 of
approximately $10 million. The funded status at the end of fiscal year 2009, and
the need for additional future required contributions, will depend primarily on
the actual return on assets during the year and the discount rate at the end of
the year.

Environmental
Laws

Surface Mining Control and
Reclamation Act. The Surface Mining Control and Reclamation Act,
(“SMCRA”), which is administered by the Office of Surface Mining Reclamation and
Enforcement (“OSM”), establishes mining, environmental protection and
reclamation standards for all aspects of surface mining as well as many aspects
of deep mining. The SMCRA and similar state statutes require, among other
things, the restoration of mined property in accordance with specified standards
and an approved reclamation plan. In addition, the Abandoned Mine Land Fund,
which is part of the SMCRA, imposes a fee on all current mining operations, the
proceeds of which are used to restore mines closed before 1977. The maximum tax
is $0.315 per ton on surface-mined coal and $0.135 per ton on deep-mined coal. A
mine operator must submit a bond or otherwise secure the performance of its
reclamation obligations. Mine operators must receive permits and permit renewals
for surface mining operations from the OSM or, where state regulatory agencies
have adopted federally approved state programs under the act, the appropriate
state regulatory authority. We accrue for reclamation and mine-closing
liabilities in accordance with Statement of Financial Accounting Standard
(“SFAS”) No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”)
(see Note 9 to the Notes to Consolidated Financial Statements).

Clean Water Act. Section 301
of the Clean Water Act prohibits the discharge of a pollutant from a point
source into navigable waters of the United States except in accordance with a
permit issued under either Section 402 or Section 404 of the Clean Water Act.
Navigable waters are broadly defined to include streams, even those that are not
navigable in fact, and may include wetlands. All mining operations in Appalachia
generate excess material, which are typically placed in fills in adjacent
valleys and hollows. Likewise, coal refuse disposal areas and coal processing
slurry impoundments are located in valleys and hollows. These areas frequently
contain intermittent or perennial streams, which are considered navigable waters
under the Clean Water Act. An operator must secure a Clean Water Act permit
before filling such streams. For approximately the past twenty-five years,
operators have secured Section 404 fill permits that authorize the filling of
navigable waters with material from various forms of coal mining. Operators have
also obtained permits under Section 404 for the construction of slurry
impoundments. Discharges from these structures require permits under Section 402
of the Clean Water Act. Section 402 discharge permits are generally not suitable
for authorizing the construction of fills in navigable waters.

16

Clean Air Act. Coal contains
impurities, including sulfur, mercury, chlorine, nitrogen oxide and other
elements or compounds, many of which are released into the air when coal is
burned. The Clean Air Act and corresponding state laws extensively regulate
emissions into the air of particulate matter and other substances, including
sulfur dioxide, nitrogen oxide and mercury. Although these regulations apply
directly to impose certain requirements for the permitting and operation of our
mining facilities, by far their greatest impact on us and the coal industry
generally is the effect of emission limitations on utilities and other
customers. Owners of coal-fired power plants and industrial boilers have been
required to expend considerable resources to comply with these air pollution
standards. The United States Environmental Protection Agency (“EPA”) has imposed
or attempted to impose tighter emission restrictions in a number of areas, some
of which are currently subject to litigation. The general effect of such tighter
restrictions could be to reduce demand for coal. This in turn may result in
decreased production and a corresponding decrease in revenue and profits.

National Ambient Air Quality
Standards. Ozone is produced by a combination of two precursor
pollutants: volatile organic compounds and nitrogen oxide, a by-product of coal
combustion. Particulate matter is emitted by sources burning coal as fuel,
including coal fired power plants. States are required to submit to EPA
revisions to their State Implementation Plans (“SIPs”) that demonstrate the
manner in which the states will attain National Ambient Air Quality Standards
(“NAAQS”) every time a NAAQS is revised by EPA. In 2006, EPA adopted a new NAAQS
for fine particulate matter, which a
number of states and environmental advocacy groups challenged as not
sufficiently stringent to satisfy Clean Air Act requirements; in February 2009,
the United States Court of Appeals for the District of Columbia Circuit agreed
that EPA had inadequately explained its decision regarding several aspects of
the NAAQS and remanded those to EPA for reconsideration, a process that could
lead to more stringent NAAQS for fine particulate matter. EPA also
adopted a more stringent ozone NAAQS on March 27, 2008. Revised SIPs for both
ozone and fine particulates could require electric power generators to further
reduce particulate, nitrogen oxide and sulfur dioxide emissions. In addition to
the SIP process, the Clean Air Act permits states to assert claims against
sources in other “upwind” states alleging that emission sources including coal
fired power plants in the upwind states are preventing the “downwind” states
from attaining a NAAQS. The new NAAQS for ozone and fine particulates, as
well as claims by affected states, could result in additional controls being
required of coal fired power plants and we are unable to predict the effect on
markets for our coal.

Acid Rain Control Provisions.
The acid rain control provisions promulgated as part of the Clean Air Act
Amendments of 1990 in Title IV of the Clean Air Act (“Acid Rain program”)
required reductions of sulfur dioxide emissions from power plants. The Acid Rain
program is now a mature program and we believe that any market impacts of the
required controls have likely been factored into the price of coal in the
national coal market.

Regional Haze Program. EPA
promulgated a regional haze program designed to protect and to improve
visibility at and around so-called Class I Areas, which are generally National
Parks, National Wilderness Areas and International Parks. This program may
restrict the construction of new coal-fired power plants whose operation may
impair visibility at and around the Class I Areas. Moreover, the program
requires certain existing coal-fired power plants to install additional control
measures designed to limit haze-causing emissions, such as sulfur dioxide,
nitrogen oxide and particulate matter. States were required to submit Regional
Haze SIPs to EPA by December 17, 2007. Many states did not meet the December 17,
2007, deadline and we are unable to predict the impact on the coal market of the
failure to submit Regional Haze SIPs by the deadline or of any subsequent
submissions deadlines.

New Source Review Program.
Under the Clean Air Act, new and modified sources of air pollution must meet
certain new source standards (“New Source Review Program”). In the late 1990s,
EPA filed lawsuits against many coal-fired plants in the eastern United States
alleging that the owners performed non-routine maintenance, causing increased
emissions that should have triggered the application of these new source
standards. Some of these lawsuits have been settled, with the owners agreeing to
install additional pollution control devices in their coal-fired plants. The
remaining litigation and the uncertainty around the New Source Review Program
rules could adversely impact utilities’ demand for coal in general or coal with
certain specifications, including the coal we produce.

Multi-Pollutant Strategies.
In March 2005, EPA issued two closely related rules designed to significantly
reduce levels of sulfur dioxide, nitrogen oxide and mercury: the Clean Air
Interstate Rule (“CAIR”) and the Clean Air Mercury Rule (“CAMR”). CAIR sets a
“cap-and-trade” program in 28 states and the District of Columbia to establish
emissions limits for sulfur dioxide and nitrogen oxide, by allowing utilities to
buy and sell credits to assist in achieving compliance with the NAAQS for 8-hour
ozone and fine particulates. CAMR as promulgated will cut mercury emissions
nearly 70% by 2018 through a “cap-and-trade” program. Both rules were challenged
in numerous lawsuits and the United States Court of Appeals for the District of
Columbia Circuit vacated CAMR and remanded it to EPA for reconsideration on
February 8, 2008. In February 2009, EPA announced its intention to develop a
technology-based standard under Section 112 of the Clean Air Act to address
mercury emissions rather than pursue the “cap-and-trade” approach of CAMR. The
same court vacated the CAIR on July 11, 2008, but subsequently revised its
remedy to a remand to EPA for reconsideration on December 23, 2008. EPA is
preparing its response to the remand, but the court did not impose a response
date. Regardless of the outcome of litigation on either rule, stricter controls
on emissions of SO2, NOX and
mercuryare
likely in some form. Any such controls may have an impact on the demand for our
coal.

17

Global
Climate Change

The
United States has not implemented the 1992 Framework Convention on Global
Climate Change (“Kyoto Protocol”), which became effective for many countries on
February 16, 2005. The Kyoto Protocol was intended to limit or reduce emissions
of greenhouse gases, such as carbon dioxide. The United States has
not ratified the emission targets of the Kyoto Protocol or any other greenhouse
gas agreement among parties.

Nevertheless,
global climate change continues to attract considerable public and scientific
attention and a considerable amount of legislative attention in the United
States is being paid to global climate change and the reduction of greenhouse
gas emissions, particularly from coal combustion by power
plants. Enactment of laws and passage of regulations regarding
greenhouse gas emissions by the United States or some of its states, or other
actions to limit carbon dioxide emissions, could result in electric generators
switching from coal to other fuel sources.

Permitting
and Compliance

Our
operations are principally regulated under surface mining permits issued
pursuant to the SMCRA and state counterpart laws. Such permits are issued for
terms of five years with the right of successive renewal. We currently have over
500 surface mining permits. In conjunction with the surface mining permits, most
operations hold national pollutant discharge elimination system permits pursuant
to the Clean Water Act and state counterpart water pollution control laws for
the discharge of pollutants to waters. These permits are issued for terms of
five years. Additionally, the Clean Water Act requires permits for operations
that fill waters of the United States. Valley fills and refuse impoundments are
authorized under permits issued under the Clean Water Act by the United States
Army Corps of Engineers. Additionally, certain surface mines and preparation
plants have permits issued pursuant to the Clean Air Act and state counterpart
clean air laws allowing and controlling the discharge of air pollutants. These
permits are primarily permits allowing initial construction (not operation) and
they do not have expiration dates.

We
believe we have obtained all permits required for current operations under the
SMCRA, Clean Water Act and Clean Air Act and corresponding state laws. We
believe that we are in compliance in all material respects with such permits,
and routinely correct violations in a timely fashion in the normal course of
operations. The expiration dates of the permits are largely immaterial as the
law provides for a right of successive renewal. The cost of obtaining surface
mining, clean water and air permits can vary widely depending on the scientific
and technical demonstrations that must be made to obtain the permits. However,
our cost of obtaining a permit is rarely more than $500,000 and our cost of
obtaining a renewal is rarely more than $5,000. It is impossible to predict the
full impact of future judicial, legislative or regulatory developments on our
operations, because the standards to be met, as well as the technology and
length of time available to meet those standards, continue to develop and
change.

We
believe, based upon present information available to us, that accruals with
respect to future environmental costs are adequate. For further discussion of
our costs, see Note 9 to the Notes to Consolidated Financial Statements.
However, the imposition of more stringent requirements under environmental laws
or regulations, new developments or changes regarding site cleanup costs or the
allocation of such costs among potentially responsible parties, or a
determination that we are potentially responsible for the release of hazardous
substances at sites other than those currently identified, could result in
additional expenditures or the provision of additional accruals in expectation
of such expenditures.

Comprehensive
Environmental Response, Compensation and Liability Act

The
Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”),
and similar state laws affect coal mining operations by, among other things,
imposing cleanup requirements for threatened or actual releases of hazardous
substances that may endanger public health or welfare or the environment. Under
CERCLA and similar state laws, joint and several liability may be imposed on
waste generators, site owners and lessees and others regardless of fault or the
legality of the original disposal activity. Although EPA excludes most wastes
generated by coal mining and processing operations from the hazardous waste
laws, such wastes can, in certain circumstances, constitute hazardous substances
for the purposes of CERCLA. In addition, the disposal, release or spilling of
some products used by coal companies in operations, such as chemicals, could
implicate the liability provisions of the statute. Under EPA’s Toxic Release
Inventory process, companies are required annually to report the use,
manufacture or processing of listed toxic materials that exceed defined
thresholds, including chemicals used in equipment maintenance, reclamation,
water treatment and ash received for mine placement from power generation
customers. Our current and former coal mining operations incur, and will
continue to incur, expenditures associated with the investigation and
remediation of facilities and environmental conditions under
CERCLA.

18

Endangered
Species Act

The federal
Endangered Species Act and counterpart state legislation protect species
threatened with possible extinction. Protection of endangered species may have
the effect of prohibiting or delaying us from obtaining mining permits and may
include restrictions on timber harvesting, road building and other mining or
agricultural activities in areas containing the affected species. Based on the
species that have been identified on our properties to date and the current
application of applicable laws and regulations, we do not believe there are any
species protected under the Endangered Species Act that would materially and
adversely affect our ability to mine coal from our properties in accordance with
current mining plans.

Available
Information

We make
available, free of charge through our Internet website, www.masseyenergyco.com,
our annual report, quarterly reports, current reports, proxy statements, Section
16 reports and other information (and any amendments thereto) as soon as
practicable after filing or furnishing the material to the SEC, in addition to,
our Corporate Governance Guidelines, codes of ethics and the charters of the
Audit, Compensation, Executive, Finance, Governance and Nominating, and Safety,
Environmental, and Public Policy Committees. These materials also may be
requested at no cost by telephone at (866) 814-6512 or by mail at: Massey Energy
Company, Post Office Box 26765, Richmond, Virginia 23261, Attention: Investor
Relations.

Executive
Officers of the Registrant

Incorporated
by reference into this Part I is the information set forth in Part III, Item 10
under the caption “Executive Officers of the Registrant” (included herein
pursuant to Item 401(b) of Regulation S-K).

********************

GLOSSARY
OF SELECTED TERMS

Ash. Impurities consisting of
iron, aluminum and other incombustible matter that are contained in coal. Since
ash increases the weight of coal, it adds to the cost of handling and can affect
the burning characteristics of coal.

Bituminous coal. The most
common type of coal with moisture content less than 20% by weight and heating
value of 10,500 to 14,000 Btu per pound.

British thermal unit, or
“Btu.” A measure of the thermal energy required to raise the temperature
of one pound of pure liquid water one degree Fahrenheit at the temperature at
which water has its greatest density (39 degrees Fahrenheit).

Central Appalachia. Coal
producing states and regions of eastern Kentucky, eastern Tennessee, western
Virginia and southern West Virginia.

Coal seam. Coal deposits
occur in layers. Each layer is called a “seam.”

Coke. A hard, dry carbon
substance produced by heating coal to a very high temperature in the absence of
air. Coke is used in the manufacture of iron and steel. Its production results
in a number of useful byproducts.

Compliance coal. Described in
Item 1. Business, under the heading “Coal Reserves.”

Continuous miner. A mining
machine with a continuously rolling cutting cylinder used in underground and
highwall mining to cut coal from the seam and load it onto conveyors or into
shuttle cars in a continuous operation.

Direct-ship coal. Coal that
is shipped without first being processed in a preparation plant.

Deep mine. An underground
coal mine.

Dragline. A large machine
used in the surface mining process to remove the overburden, or layers of earth
and rock covering a coal seam. The dragline has a large bucket suspended from
the end of a long boom. The bucket, which is suspended by cables, is able to
scoop up substantial amounts of overburden as it is dragged across the
excavation area.

19

Fossil fuel. Fuel such as
coal, petroleum or natural gas formed from the fossil remains of organic
material.

Highwall mining. Described in
Item 1. Business, under the heading “Mining Methods.”

High vol met coal. Coal that
averages approximately 35% volatile matter. Volatile matter refers to the
impurities that become gaseous when heated to certain temperatures.

Illinois Basin. The Illinois
Basin consists of the coal producing areas in Illinois, Indiana and western
Kentucky.

Industrial coal. Coal used by
industrial steam boilers to produce electricity or process steam. It generally
is lower in Btu heat content and higher in volatile matter than metallurgical
coal.

Long-term contracts.
Contracts with terms of one year or longer.

Longwall mining. Described in
Item 1. Business, under the heading “Mining Methods.”

Low vol met coal. Coal that
averages approximately 20% volatile matter. Volatile matter refers to the
impurities that become gaseous when heated to certain temperatures.

Metallurgical coal. The
various grades of coal suitable for carbonization to make coke for steel
manufacture. Also known as “met” coal, it possesses four important qualities:
volatility, which affects coke yield; the level of impurities, which affects
coke quality; composition, which affects coke strength; and basic
characteristics, which affect coke oven safety. Met coal has a particularly high
Btu heat content, but low ash content.

Mine. A mine consists of
those operating assets necessary to produce coal from surface or underground
locations.

Nitrogen oxide (NOx).
Nitrogen oxide is produced as a gaseous by-product of coal
combustion.

Northern Appalachia. Northern
Appalachia consists of the bituminous coal producing areas in the states of
Pennsylvania, Ohio and Maryland and in the northern part of West
Virginia.

Overburden ratio. The amount
of overburden that must be removed to excavate a given quantity of coal. It is
commonly expressed in cubic yards per ton of coal or as a ratio comparing the
thickness of the overburden with the thickness of the coal bed.

Pillar. An area of coal left
to support the overlying strata in an underground mine, sometimes left
permanently to support surface structures.

Powder River Basin. The
Powder River Basin consists of the coal producing areas in southeast Montana and
northeast Wyoming.

Preparation plant. A
preparation plant is a facility for crushing, sizing and washing coal to remove
rock and other impurities to prepare it for use by a particular customer.
Preparation plants are usually located on a mine site, although one plant may
serve several mines. The washing process has the added benefit of removing some
of the coal’s sulfur content.

Probable
reserves. Described in
Item 1. Business, under the heading “Coal Reserves.”

Proven reserves. Described in
Item 1. Business, under the heading “Coal Reserves.”

Reclamation. The process of
restoring land and the environment to their approximate original state following
mining activities. The process commonly includes “recontouring” or reshaping the
land to its approximate original appearance, restoring topsoil and planting
native grass and ground covers. Reclamation operations are usually underway
before the mining of a particular site is completed. Reclamation is closely
regulated by both state and federal law.

Reserve. Described in Item 1.
Business, under the heading “Coal Reserves.”

20

Resource Group. An
organizational unit, generally located within a specific geographic locale, that
contains one or more of the following operations related to the mining,
processing or shipping of coal: underground mine, surface mine,
preparation plant or load-out facility.

Roof. The stratum of rock or
other mineral above a coal seam; the overhead surface of a coal working
place.

Room and pillar mining.
Described in Item 1. Business, under the heading “Mining Methods.”

Scrubber (flue gas desulfurization
unit). Any of several forms of chemical/physical devices that operate to
neutralize sulfur and other greenhouse gases formed during coal combustion.
These devices combine the sulfur in gaseous emissions with other chemicals to
form inert compounds, such as gypsum, that must then be removed for disposal.
Although effective in substantially reducing sulfur from combustion gases,
scrubbers require about 6% to 7% of a power plant’s electrical output and
thousands of gallons of water to operate.

Steam coal.
Coal used by power plants and industrial steam
boilers to produce electricity or process steam. It generally is lower in Btu
heat content and higher in volatile matter than metallurgical coal. Also known
as utility coal.

Stoker coal. Coal that is
sized to a specific, standard range. Stoker coal is typically one quarter inch
by one and one quarter to one and three quarter inch.

Sulfur. One of the elements
present in varying quantities in coal that reacts with air when coal is burned
to form sulfur dioxide.

Sulfur content. Coal is
commonly described by its sulfur content due to the importance of sulfur in
environmental regulations. “Low sulfur” coal has a variety of definitions, but
typically is used to describe coal consisting of 1.0% or less
sulfur.

Sulfur dioxide (SO2). Sulfur dioxide is produced
as a gaseous by-product of coal combustion.

Surface mining. Described in
Item 1. Business, under the heading “Mining Methods.”

Tons. A “short” or net ton is
equal to 2,000 pounds. A “long” or British ton is approximately 2,240 pounds; a
“metric” ton is approximately 2,205 pounds. The short ton is the unit of measure
referred to in this Annual Report on Form 10-K.

Underground mine. Also known
as a “deep” mine. Usually located several hundred feet below the earth’s
surface, an underground mine’s coal is removed mechanically and transferred by
shuttle car or conveyor to the surface.

Unit train. A railroad train
of a specified number of railroad cars carrying only coal. A typical unit train
can carry at least 10,000 tons of coal in a single shipment.

Utility coal. Coal used by
power plants to produce electricity or process steam. It generally is lower in
Btu heat content and higher in volatile matter than metallurgical coal. Also
known as steam coal.

********************

21

Item
1A. Risk Factors

We are
subject to a variety of risks, including, but not limited to, those risk factors
set forth below and those referenced herein to other Items contained in this
Annual Report on Form 10-K, including Item 1. Business, under the headings
“Customers and Coal Contracts,” “Competition,” “Environmental, Safety and Health
Laws and Regulations,” Item 3. Legal Proceedings and Item 7. Management’s
Discussion and Analysis of Financial Condition and Results of Operations
(“MD&A”), under the headings “Critical Accounting Estimates and
Assumptions,” “Certain Trends and Uncertainties” and elsewhere in
MD&A.

We
could be negatively impacted by the competitiveness of the markets in which we
compete and declines in the market demand for coal.

We
compete with coal producers in various regions of the United States and overseas
for domestic and international sales. Continued domestic demand for our coal and
the prices that we will be able to obtain primarily will depend upon coal
consumption patterns of the domestic electric utility industry and the domestic
steel industry. Consumption by the domestic utility industry is affected by the
demand for electricity, environmental and other governmental regulations,
technological developments and the price of competing coal and alternative fuel
supplies including nuclear, natural gas, oil and renewable energy sources,
including hydroelectric power. Consumption by the domestic steel industry is
primarily affected by economic growth and the demand for steel used in
construction as well as appliances and automobiles. In recent years and until a
worldwide financial crisis developed in mid-2008, the competitive environment
for coal was impacted by sustained growth in a number of the largest markets in
the world, including the United States, China, Japan and India, where demand for
both electricity and steel supported pricing for steam and metallurgical coal.
The financial crisis has reduced demand and increased competition in supplying
these markets. The cost of ocean transportation and the value of the United
States dollar in relation to foreign currencies significantly impact the
relative attractiveness of our coal as we compete on price with other foreign
coal producing sources. Increased competition by competing coal producers or
producers of alternate fuels in the markets in which we serve could cause a
decrease in demand and/or pricing for our coal, adversely impacting our cash
flows, results of operations or financial condition.

Portions
of our coal reserves possess quality characteristics that enable us to mine,
process and market them as either metallurgical coal or high quality steam coal,
depending on the prevailing conditions in the markets for metallurgical and
steam coal. A decline in the metallurgical market relative to the steam market
could cause us to shift coal from the metallurgical market to the steam market,
potentially reducing the price we could obtain for this coal and adversely
impacting our cash flows, results of operations or financial
condition.

Demand
for our coal depends on its price and quality and the cost of transporting it to
our customers.

Coal
prices are influenced by a number of factors and may vary dramatically by
region. The two principal components of the price of coal are the price of coal
at the mine, which is influenced by mine operating costs and coal quality, and
the cost of transporting coal from the mine to the point of use. The cost of
mining the coal is influenced by geologic characteristics such as seam
thickness, overburden ratios and depth of underground reserves. Underground
mining is generally more expensive than surface mining as a result of higher
costs for labor (including reserves for future costs associated with labor
benefits and health care) and capital costs (including costs for mining
equipment and construction of extensive ventilation systems). As of January 31,
2009, we operated 46 active underground mines, including two which employ both
room and pillar and longwall mining, and 20 active surface mines, with 11
highwall miners.

Transportation
costs represent a significant portion of the delivered cost of coal and, as a
result, the cost of delivery is a critical factor in a customer’s purchasing
decision. Increases in transportation costs could make coal a less competitive
source of energy. Such increases could have a material impact on our ability to
compete with other energy sources and on our cash flows, results of operations
or financial condition. Conversely, significant decreases in transportation
costs could result in increased competition from coal producers in other parts
of the country or the world, including coal imported into the United States
(several United States ports have recently increased or announced plans to
increase their capacity to handle imported coal). For instance, coal mines in
the western United States could become an increasingly attractive source of coal
to consumers in the eastern part of the United States if the costs of
transporting coal from the west were significantly reduced and/or rail capacity
was increased.

A
significant decline in coal prices in general could adversely affect our
operating results and cash flows.

Our
results are highly dependent upon the prices we receive for our coal. Decreased
demand for coal, both domestically and internationally, is causing spot prices
and the prices we are able to negotiate on long-term contracts to decline. The
lower prices could negatively affect our cash flows, results of operations or
financial condition, if we are unable to increase productivity and/or decrease
costs in order to maintain our margins.

22

We
depend on continued demand from our customers.

Reduced
demand from or the loss of our largest customers could have an adverse impact on
our ability to achieve projected revenue. Decreases in demand may result from,
among other things, a reduction in consumption by the electric generation
industry and/or the steel industry, the availability of other sources of fuel at
cheaper costs and a general slow-down in the economy. When our contracts with
customers expire, there can be no assurance that the customers either will
extend or enter into new long-term contracts or, in the absence of long-term
contracts, that they will continue to purchase the same amount of coal as they
have in the past or on terms, including pricing terms, as favorable as under
existing arrangements. For example, our largest customer, Constellation,
accounted for 11% of fiscal year 2008 Produced coal revenue. For fiscal year
2009, our contracted sales to Constellation currently represent approximately
26% of our projected produced coal tonnage and 18% of our
projected Produced coal revenue.There are
no other customers to whom we expect to sell 10% or more of produced tons or to
account for 10% or more of Produced coal revenue in 2009. In the
event that a large customer account is lost or a long-term contract is not
renewed, profits could suffer if alternative buyers are not willing to purchase
our coal on comparable terms.

There
may be adverse changes in price, volume or terms of our existing coal supply
agreements.

Many of
our coal supply agreements contain provisions that permit the parties to adjust
the contract price upward or downward at specified times. These contracts may be
adjusted based on inflation or deflation and/or changes in the factors affecting
the cost of producing coal, such as taxes, fees, royalties and changes in the
laws regulating the mining, production, sale or use of coal. In a limited number
of contracts, failure of the parties to agree on a price under those provisions
may allow either party to terminate the contract. Coal supply agreements also
typically contain force majeure provisions allowing temporary suspension of
performance by us or the customer for the duration of specified events beyond
the control of the affected party. Most coal supply agreements contain
provisions requiring us to deliver coal meeting quality thresholds for certain
characteristics such as Btu, sulfur content, ash content, grindability and ash
fusion temperature. Failure to meet these specifications could result in
economic penalties, including price adjustments, the rejection of deliveries or
termination of the contracts.

Our
financial condition may be adversely affected if we are required by some of our
customers to provide performance assurances for certain below-market sales
contracts.

Contracts
covering a significant portion of our contracted sales tons contain provisions
that could require us to provide performance assurances if we experience a
material adverse change or, under certain other contracts, if the customer
believes our creditworthiness has become unsatisfactory. Generally, under such
contracts, performance assurances are only required if the contract price per
ton of coal is below the current market price of the coal. Certain of the
contracts limit the amount of performance assurance to a per ton amount in
excess of the contract price, while others have no limit. The performance
assurances are generally provided by the posting of a letter of credit, cash
collateral, other security, or a guaranty from a creditworthy guarantor. As of
December 31, 2008, we have not received any requests from any of our customers
to provide performance assurances. If we are required to post performance
assurances on some or all of our contracts with performance assurances
provisions, there could be a material adverse impact on our cash flows, results
of operations or financial condition.

The
level of our indebtedness could adversely affect our ability to grow and compete
and prevent us from fulfilling our obligations under our contracts and
agreements.

At
December 31, 2008, we had $1,465.6 million of total indebtedness outstanding,
which represented 58.6% of our total book capitalization. During 2008, we issued
$690 million of 3.25% convertible senior notes due 2015 (“3.25% Notes”) and
tendered for and retired $313.1 million of our 6.625% senior notes due 2010
(“6.625% Notes”). We have significant debt, lease and royalty
obligations. Our ability to satisfy debt service, lease and royalty obligations
and to effect any refinancing of indebtedness will depend upon future operating
performance, which will be affected by prevailing economic conditions in the
markets that we serve as well as financial, business and other factors, many of
which are beyond our control. We may be unable to generate sufficient cash flow
from operations and future borrowings, or other financings may be unavailable in
an amount sufficient to enable us to fund our debt service, lease and royalty
payment obligations or our other liquidity needs.

23

Our
relative amount of debt could have material consequences to our business,
including, but not limited to: (i) making it more difficult to satisfy debt
covenants and debt service, lease payments and other obligations; (ii) making it
more difficult to pay quarterly dividends as we have in the past; (iii)
increasing our vulnerability to general adverse economic and industry
conditions; (iv) limiting our ability to obtain additional financing to fund
future acquisitions, working capital, capital expenditures or other general
corporate requirements; (v) reducing the availability of cash flows from
operations to fund acquisitions, working capital, capital expenditures or other
general corporate purposes; (vi) limiting our flexibility in planning
for, or reacting to, changes in the business and the industry in which we
compete; or (vii) placing us at a competitive disadvantage with competitors with
relatively lower amounts of debt. Any of the above-listed factors could have an
adverse effect on our business, financial condition and results of operations
and our ability to meet our debt payment obligations.

The
covenants in our credit facility and the indentures governing debt instruments
impose restrictions that may limit our operating and financial
flexibility.

Our $175
million asset-based loan credit facility (“ABL Facility”) contains a number of
significant restrictions and covenants that may limit our ability and our
subsidiaries’ ability to, among other things: (1) incur additional indebtedness;
(2) increase common stock dividends above specified levels; (3) make loans and
investments; (4) prepay, redeem or repurchase debt; (5) engage in mergers,
consolidations and asset dispositions; (6) engage in affiliate transactions; (7)
create any lien or security interest in any real property or equipment; (8)
engage in sale and leaseback transactions; and (9) make distributions from
subsidiaries. A decline in our operating results or other adverse factors,
including a significant increase in interest rates, could result in us being
unable to comply with certain covenants contained in the ABL Facility, which
become operative only when our Average Excess Availability (as defined in the
ABL Facility) is less than $30 million. These financial covenants include a
Minimum Consolidated Fixed Charge Ratio of 1.00 to 1.00 and a minimum
Consolidated Net Worth of $550 million under the terms of the ABL Facility (currently
approximately $400 million as adjusted for Accounting
Changes).

The
indentures governing certain of our senior notes also contain a number of
significant restrictions and covenants that may limit our ability and our
subsidiaries’ ability to, among other things: (1) incur additional indebtedness;
(2) subordinate indebtedness to other indebtedness unless such subordinated
indebtedness is also subordinated to the notes; (3) pay dividends or make other
distributions or repurchase or redeem our stock or subordinated indebtedness;
(4) make investments; (5) sell assets and issue capital stock of restricted
subsidiaries; (6) incur liens; (7) enter into agreements restricting our
subsidiaries’ ability to pay dividends; (8) enter into sale and leaseback
transactions; (9) enter into transactions with affiliates; and (10) consolidate,
merge or sell all or substantially all of our assets. If we violate these
covenants and are unable to obtain waivers from our lenders, our debt under
these agreements would be in default and could be accelerated by the lenders
and, in the case of an event of default under our ABL Facility, it could permit
the lenders to foreclose on our assets securing the loans under the ABL
Facility. If the indebtedness is accelerated, we may not be able to repay our
debt or borrow sufficient funds to refinance it. Even if we are able to obtain
new financing, it may not be on commercially reasonable terms or on terms that
are acceptable to us. If our debt is in default for any reason, our cash flows,
results of operations or financial condition could be materially and adversely
affected. In addition, complying with these covenants may also cause us to take
actions that are not favorable to our shareholders and holders of our senior
notes and may make it more difficult for us to successfully execute our business
strategy and compete against companies that are not subject to such
restrictions.

We
are subject to being adversely affected by the potential inability to renew or
obtain surety bonds.

Federal
and state laws require bonds to secure our obligations to reclaim lands used for
mining, to pay federal and state workers’ compensation and to satisfy other
miscellaneous obligations. These bonds are typically renewable annually. Surety
bond issuers and holders may not continue to renew the bonds or may demand
additional collateral upon those renewals. We are also subject to increases in
the amount of surety bonds required by federal and state laws as these laws
change or the interpretation of these laws changes. Our failure to maintain, or
inability to acquire, surety bonds that are required by state and federal law
would have a material adverse impact on us, possibly by prohibiting us from
developing properties that we desire to develop. That failure could result from
a variety of factors including the following: (i) lack of availability,
higher expense or unfavorable market terms of new bonds; (ii) restrictions
on availability of collateral for current and future third-party surety bond
issuers under the terms of our senior notes or revolving credit facilities;
(iii) our inability to meet certain financial tests with respect to a
portion of the post-mining reclamation bonds; and (iv) the exercise by
third-party surety bond issuers of their right to refuse to renew or issue new
bonds.

A key
component of our future success is our ability to continue acquiring coal
reserves for development that have the geological characteristics that allow
them to be economically mined. Replacement reserves may not be available or, if
available, may not be capable of being mined at costs comparable to those
characteristics of the depleting mines. An inability to continue acquiring
economically recoverable coal reserves could have a material impact on our cash
flows, results of operations or financial condition.

24

We
face numerous uncertainties in estimating economically recoverable coal
reserves, and inaccuracies in estimates could result in lower than expected
revenues, higher than expected costs and decreased
profitability.

There are numerous
uncertainties inherent in estimating quantities and values of economically
recoverable coal reserves, including many factors beyond our control. As a
result, estimates of economically recoverable coal reserves are by their nature
uncertain. Information about our reserves consists of estimates based on
engineering, economic and geological data assembled and analyzed by us. Some of
the factors and assumptions that impact economically recoverable reserve
estimates include: (1) geological conditions; (2) historical
production from the area compared with production from other producing areas;
(3) the effects of regulations and taxes by governmental agencies;
(4) future prices; and (5) future operating costs.

Each of
these factors may vary considerably from the assumptions used in estimating
reserves. For these reasons, estimates of the economically recoverable
quantities of coal attributable to a particular group of properties may vary
substantially. As a result, our estimates may not accurately reflect our actual
reserves. Actual production, revenues and expenditures with respect to reserves
will likely vary from estimates, and these variances may be
material.

Defects
in title or loss of any leasehold interests in our properties could limit our
ability to mine our properties or result in significant unanticipated
costs.

A
significant portion of our mining operations occurs on properties that we lease.
Title defects or the loss of leases could adversely affect our ability to mine
the reserves covered by those leases. Our current practice is to obtain a title
review from a licensed attorney prior to leasing property. We generally have not
obtained title insurance in connection with acquisitions of coal reserves. In
some cases, the seller or lessor warrants property title. Separate title
confirmation sometimes is not required when leasing reserves where mining has
occurred previously. Our right to mine some of our reserves may be adversely
affected if defects in title or boundaries exist. In order to obtain leases to
conduct our mining operations on property where these defects exist, we may have
to incur unanticipated costs. In addition, we may not be able to successfully
negotiate new leases for properties containing additional reserves, or maintain
our leasehold interests in properties where we have not commenced mining
operations during the term of the lease.

If
the coal industry experiences overcapacity in the future, our profitability
could be impaired.

An
increase in the demand for coal could attract new investors to the coal
industry, which could spur the development of new mines, and result in added
production capacity throughout the industry. During 2008 we increased our coal
production having added 19 additional coal mines in the last twelve months. By
the end of 2008, our expansion work was continuing and was largely complete.
Further expansion plans for 2009 have been deferred or cancelled in light of the
changes in market conditions. Several of our competitors have also been
increasing their production capacity; however, the recent global financial
crisis has caused some of these competitors to announce delays in their
expansion projects. Higher price levels of coal could further encourage the
development of expanded capacity by new or existing coal producers. Any
resulting increases in capacity could further reduce coal prices and reduce our
margins.

An
inability of brokerage sources or contract miners to fulfill the delivery terms
of their contracts with us could reduce our profitability.

We
sometimes obtain coal from brokerage sources and contract miners to fulfill
deliveries under our coal supply agreements. Some of our brokerage sources
and contract miners may experience adverse geologic mining, escalated operating
costs and/or financial difficulties that make their delivery of coal to us at
the contracted price difficult or uncertain. Our profitability or exposure to
loss on transactions or relationships such as these may be affected based upon
the reliability of the supply or the ability to substitute, when economical,
third-party coal sources, with internal production or coal purchased in the
market and other factors.

Our
operations are dependant on reliable supplies of mining equipment, replacement
parts, explosives, diesel fuel, tires, magnetite and steel-related products
(including roof bolts). If the cost of any mining equipment or key supplies
increases significantly, or if they should become unavailable due to higher
industry-wide demand or less production by suppliers, there could be an adverse
impact on our cash flows, results of operations or financial condition. The
supplier base providing mining materials and equipment has been relatively
consistent in recent years, although there continues to be consolidation. This
consolidation has resulted in a situation where purchases of explosives and
certain underground mining equipment are concentrated with single suppliers. In
recent years, mining industry demand growth has exceeded supply growth for
certain surface and underground mining equipment and heavy equipment tires. As a
result, lead times for certain items have generally increased.

25

Transportation
disruptions could impair our ability to sell coal.

We are dependent on
our transportation providers to provide access to markets. Disruption of
transportation services because of weather-related problems, strikes, lockouts,
fuel shortages or other events could temporarily impair our ability to supply
coal to customers. Our ability to ship coal could be negatively impacted by a
reduction in available and timely rail service. Lack of sufficient resources to
meet a rapid increase in demand, a greater demand for transportation to export
terminals and rail line congestion all could contribute to a disruption and
slowdown in rail service. We continue to experience rail service delays and
disruptions in service which are negatively impacting our ability to deliver
coal to customers and which may adversely affect our results of
operations.

Severe
weather may affect our ability to mine and deliver coal.

Severe
weather, including flooding and excessive ice or snowfall, when it occurs, can
adversely affect our ability to produce, load and transport coal, which may
negatively impact our cash flows, results of operations or financial
condition.

Federal,
state and local laws and government regulations applicable to operations
increase costs and may make our coal less competitive than other coal
producers.

We incur
substantial costs and liabilities under increasingly strict federal, state and
local environmental, health and safety and endangered species laws, regulations
and enforcement policies. Failure to comply with these laws and regulations may
result in the assessment of administrative, civil and criminal penalties, the
imposition of cleanup and site restoration costs and liens, the issuance of
injunctions to limit or cease operations, the suspension or revocation of
permits and other enforcement measures that could have the effect of limiting
production from our operations. The costs of compliance with applicable
regulations and liabilities assessed for compliance failure could have a
material adverse impact on our cash flows, results of operations or financial
condition.

New
legislation and new regulations may be adopted which could materially adversely
affect our mining operations, cost structure or our customers’ ability to use
coal. New legislation and new regulations may also require us, as well as our
customers, to change operations significantly or incur increased costs. The
United States Environmental Protection Agency (the “EPA”) has undertaken broad
initiatives to increase compliance with emissions standards and to provide
incentives to our customers to decrease their emissions, often by switching to
an alternative fuel source or by installing scrubbers or other expensive
emissions reduction equipment at their coal-fired plants.

Concerns
about the environmental impacts of coal combustion, including perceived impacts
on global climate change, are resulting in increased regulation of coal
combustion in many jurisdictions, and interest in further regulation, which
could significantly affect demand for our products.

The Clean
Air Act and similar state and local laws extensively regulate the amount of
sulfur dioxide, particulate matter, nitrogen oxides and other compounds emitted
into the air from electric power plants, which are the largest end-users of our
coal. Such regulation may require significant emissions control expenditures for
many coal-fired power plants. As a result, the generators may switch to other
fuels that generate less of these emissions or install more effective pollution
control equipment, possibly reducing future demand for coal and the construction
of coal-fired power plants. The majority of our coal supply agreements contain
provisions that allow a purchaser to terminate its contract if legislation is
passed that either restricts the use or type of coal permissible at the
purchaser’s plant or results in specified increases in the cost of coal or its
use.

26

Global
climate change continues to attract considerable public and scientific
attention. Widely publicized scientific reports, such as the Fourth Assessment
Report of the Intergovernmental Panel on Climate Change released in 2007, have
also engendered widespread concern about the impacts of human activity,
especially fossil fuel combustion, on global climate change. A considerable and
increasing amount of attention in the United States is being paid to global
climate change and to reducing greenhouse gas emissions, particularly from coal
combustion by power plants. According to the EIA report, “Emissions of
Greenhouse Gases in the United States 2007,” coal combustion accounts for 30% of
man-made greenhouse gas emissions in the United States. Legislation was
introduced in Congress in the past several years to reduce greenhouse gas
emissions in the United States and, although no bills to reduce such emissions
have yet passed either house of Congress, bills to reduce such emissions remain
pending and others are likely to be introduced. President Obama campaigned in
favor of a “cap-and-trade” program to require mandatory greenhouse gas emissions
reductions and since his election has continued to express support for such
legislation, contrary to the previous administration. The United
States Supreme Court’s 2007 decision in Massachusetts v. Environmental
Protection Agency ruled that EPA improperly declined to address carbon
dioxide impacts on climate change in a rulemaking related to new motor vehicles.
The reasoning of the court decision could affect other federal regulatory
programs, including those that directly relate to coal use. In July 2008, EPA
published an Advanced Notice of Proposed Rulemaking (ANPR) seeking comments
regarding the regulation of greenhouse gas emissions; and in February 2009 the
newly appointed administrator of EPA granted a petition by environmental
advocacy groups to reconsider an interpretive memorandum by her predecessor in
December 2008 that concluded the Clean Air Act’s Prevention of
Significant Deterioration program does not extend to carbon dioxide
emissions, a decision that could lead to carbon dioxide emissions from
coal-fired power plants being a consideration in permitting decisions. In
addition, a growing number of states in the United States are taking steps to
require greenhouse gas emissions reductions from coal-fired power plants.Enactment of laws and
promulgation of regulations regarding greenhouse gas emissions by the United
States or some of its states, or other actions to limit carbon dioxide
emissions, could result in electric generators switching from coal to other fuel
sources.

As part
of the United Nations Framework Convention on Climate Change, representatives
from 187 nations met in Bali, Indonesia in December 2007 to discuss a program to
limit greenhouse gas emissions after 2012. The United States participated in the
conference. The convention adopted what is called the “Bali Action Plan.” The
Bali Action Plan contains no binding commitments, but concludes that “deep cuts
in global emissions will be required” and provides a timetable for two years of
talks to shape the first formal addendum to the 1992 United Nations Framework
Convention on Climate Change treaty since the Kyoto Protocol. The ultimate
outcome of the Bali Action Plan, and any treaty or other arrangement ultimately
adopted by the United States or other countries, may have a material adverse
impact on the global supply and demand for coal. This is particularly true if
cost effective technology for the capture and sequestration of carbon dioxide is
not sufficiently developed. Technologies that may significantly reduce emissions
into the atmosphere of greenhouse gases from coal combustion, such as carbon
capture and sequestration (which captures carbon dioxide at major sources such
as power plants and subsequently stores it in nonatmospheric reservoirs such as
depleted oil and gas reservoirs, unmineable coal seams, deep saline formations,
or the deep ocean) have attracted and continue to attract the attention of
policy makers, industry participants, and the public. For example, in July 2008
EPA proposed rules that would establish, for the first time, requirements
specifically for wells used to inject carbon dioxide into geologic formations.
Considerable uncertainty remains, not only regarding rules that may become
applicable to carbon dioxide injection wells but also concerning liability for
potential impacts of injection, such as groundwater contamination or seismic
activity. In addition, technical, environmental, economic, or other factors may
delay, limit, or preclude large-scale commercial deployment of such
technologies, which could ultimately provide little or no significant reduction
of greenhouse gas emissions from coal combustion.

Further
developments in connection with legislation, regulations or other limits on
greenhouse gas emissions and other environmental impacts from coal combustion,
both in the United States and in other countries where we sell coal, could have
a material adverse effect on our cash flows, results of operations or financial
condition.

Our
operations may adversely impact the environment which could result in material
liabilities to us.

The processes required
to mine coal may cause certain impacts or generate certain materials that might
adversely affect the environment from time to time. The mining processes we use
could cause us to become subject to claims for toxic torts, natural resource
damages and other damages as well as for the investigation and clean up of soil,
surface water, groundwater, and other media. Such claims may arise, for example,
out of conditions at sites that we currently own or operate, as well as at sites
that we previously owned or operated, or may acquire. Our liability for such
claims may be joint and several, so that we may be held responsible for more
than our share of the contamination or other damages, or even for the entire
share.

Certain coal that we
mine needs to be cleaned at preparation plants, which generally require coal
refuse areas and/or slurry impoundments. Such areas and impoundments are subject
to extensive regulation and monitoring. Slurry impoundments have been known to
fail, releasing large volumes of coal slurry into nearby surface waters and
property, resulting in damage to the environment and natural resources, as well
as injuries to wildlife. We maintain coal refuse areas and slurry impoundments
at a number of our mining complexes. If one of our impoundments were to
fail, we could be subject to substantial claims for the resulting environmental
impact and associated liability, as well as for fines and
penalties.

27

Drainage flowing from or caused by mining activities can be acidic
with elevated levels of dissolved metals, a condition referred to as acid mine
drainage (“AMD”). Although we do not currently face material costs
associated with AMD, it is possible that we could incur significant costs in the
future.

These and
other similar unforeseen impacts that our operations may have on the
environment, as well as exposures to certain substances or wastes associated
with our operations, could result in costs and liabilities that could materially
and adversely affect us and could have a material adverse impact on our cash
flows, results of operations or financial condition.

The
Mine Safety and Health Administration (“MSHA”) or other federal or state
regulatory agencies may order certain of our mines to be temporarily or
permanently closed, which could adversely affect our ability to meet our
customers’ demands.

MSHA or
other federal or state regulatory agencies may order certain of our mines to be
temporarily or permanently closed. Our customers may challenge our issuance of
force majeure notices in connection with such closures. If these challenges
are successful, we may have to purchase coal from third-party sources to satisfy
those challenges; negotiate settlements with customers, which may include price
reductions, the reduction of commitments or the extension of the time for
delivery, terminate customers’ contracts or face claims initiated by our
customers against us. The resolution of these challenges could have a material
adverse impact on our cash flows, results of operations or financial
condition.

We
must obtain governmental permits and approvals for mining operations, which can
be a costly and time-consuming process, can result in restrictions on our
operations, and is subject to litigation that may delay or prevent us from
obtaining necessary permits.

Our
operations are principally regulated under surface mining permits issued
pursuant to the Surface Mining Control and Reclamation Act (the “SMCRA”) and
state counterpart laws. Such permits are issued for terms of five years with the
right of successive renewal. Additionally, the Clean Water Act requires permits
for operations that discharge into waters of the United States. Valley fills and
refuse impoundments are authorized under permits issued by the United States
Army Corps of Engineers. Such permitting under the Clean Water Act has been a
frequent subject of litigation by environmental advocacy groups that has
resulted in periodic declines in such permits issued by the United States Army
Corps of Engineers. Additionally, certain surface mines and preparation plants
have permits issued pursuant to the Clean Air Act and state counterpart laws
allowing and controlling the discharge of air pollutants. Regulatory authorities
exercise considerable discretion in the timing of permit issuance. Requirements
imposed by these authorities may be costly and time-consuming and may result in
delays in, or in some instances preclude, the commencement or continuation of
development or production operations. Adverse outcomes in lawsuits challenging
permits or failure to comply with applicable regulations could result in the
suspension, denial or revocation of required permits, which could have a
material adverse impact on our cash flows, results of operations or financial
condition.

The
loss of key personnel or the failure to attract qualified personnel could affect
our ability to operate the Company effectively.

The
successful management of our business is dependent on a number of key personnel.
Our future success will be affected by our continued ability to attract and
retain highly skilled and qualified personnel. There are no assurances that key
personnel will continue to be employed by us or that we will be able to attract
and retain qualified personnel in the future. Failure to retain or attract key
personnel could have an adverse affect on our cash flows, results of operations
or financial condition.

Shortages of skilled labor in the
Central Appalachian coal industry may pose a risk in achieving high levels of
productivity at competitive costs.

Coal
mining continues to be a labor-intensive industry. In recent years, we have
encountered a shortage of experienced mine workers when the demand and prices
for all specifications of coal we mine increased appreciably. The hiring of
these less experienced workers has negatively impacted our productivity and cash
costs. A continued lack of skilled miners could continue to have an adverse
impact on our labor productivity and cost and our ability to meet current
production requirements to fulfill existing sales commitments or to expand
production to meet the increased demand for coal.

At
December 31, 2008, approximately 1.8% of our total workforce was represented by
the United Mine Workers of America (the “UMWA”). Our unionized workforce is
spread out amongst five of our coal preparation plants and one smaller surface
mine. In 2008, these preparation plants handled approximately 29.3% of our coal
production. We are currently in the process of negotiating successor collective
bargaining agreements for ones that have expired. In connection with these
negotiations and with respect to our unionized operations generally, there may
be an increased risk of strikes and other labor disputes, as well as higher
labor costs. If some or all of our current open shop operations were to become
unionized, we could be subject to additional risk of work stoppages, other labor
disputes and higher labor costs, which could adversely affect the stability of
production and reduce net income.

28

Legislation has been
proposed to the United States Congress to enact a law allowing for workers to
choose union representation solely by signing election cards (“Card Check”),
which would eliminate the use of secret ballots to elect union representation.
While the impact is uncertain, if Card
Check legislation is enacted into law, it will be administratively easier for
the UMWA to unionize coal mines and may lead to more coal mines becoming
unionized.

Although
inflation in the United States has been relatively low in recent years, over the
course of the last two to three years, we have been significantly impacted by
price inflation in many of the components of our cost of produced coal
revenue, such as fuel, steel and labor. If the prices for which we sell
our coal do not increase in step with rising costs or if these costs do not
decline sufficiently, our profit margins would be reduced and our cash flows,
results of operations or financial condition would be adversely
affected.

We
are subject to various legal proceedings, which may have a material effect on
our business.

We are
parties to a number of legal proceedings incident to normal business activities.
Some of the allegations brought against us are with merit, while others are not.
There is always the potential that an individual matter or the aggregation of
many matters could have a material adverse effect on our cash flows, results of
operations or financial position. See Note 18 of the Notes to Consolidated
Financial Statements.

We
have significant reclamation and mine closure obligations. If the assumptions
underlying our accruals are materially inaccurate, we could be required to
expend greater amounts than anticipated.

SMCRA
establishes operational, reclamation and closure standards for all aspects of
surface mining as well as most aspects of deep mining. Estimates of our total
reclamation and mine-closing liabilities are based upon permit requirements and
our engineering expertise related to these requirements. The estimate of
ultimate reclamation liability is reviewed periodically by management and
engineers. The estimated liability can change significantly if actual costs vary
from assumptions or if governmental regulations change
significantly.

Our
future expenditures for postretirement benefit and pension obligations could be
materially higher than we have predicted if our underlying assumptions are
incorrect.

We are
subject to long-term liabilities under a variety of benefit plans and other
arrangements with current and former employees. These obligations have been
estimated based on actuarial assumptions, including actuarial estimates, assumed
discount rates, estimates of life expectancy, expected returns on pension plan
assets and changes in healthcare costs.

If our
assumptions relating to these benefits change in the future or are incorrect, we
may be required to record additional expenses, which would reduce our
profitability. In addition, future regulatory and accounting changes relating to
these benefits could result in increased obligations or additional costs, which
could also have a material adverse impact on our cash flows, results of
operations or financial condition. See also Notes 5, 10 and 11 of the Notes to
Consolidated Financial Statements for
further discussion.

Our
pension plans are currently underfunded and we may have to make significant cash
payments to the plans, reducing the cash available for our business

We
sponsor a qualified non-contributory defined benefit pension plan, which covers
substantially all administrative and non-union employees. We
currently expect to make contributions in 2009 of approximately $10 million. If
the performance of the assets in our pension plans does not meet our
expectations, or if other actuarial assumptions are modified, our contributions
could be higher than we expect.

The value
of the assets held in our pension plans has been adversely affected by the
recent disruptions in the financial markets, and the applicable discount rates
applied in determining our pension liabilities have also been negatively
affected by the crisis in the financial markets.As a result, as of
December 31, 2008, our annual measurement date, our pension plan was
underfunded by $63 million (based on the actuarial assumptions used for SFAS
No. 158, Employers’
Accounting for Defined Benefit Pension and Other Postretirement Plans—an
amendment of FASB Statements No. 87, 88, 106, and 132(R) (“SFAS
No. 158”)). Our pension
plans are subject to the Employee Retirement Income Security Act of 1974
(“ERISA”). Under ERISA, the Pension Benefit Guaranty Corporation, or PBGC, has
the authority to terminate an underfunded pension plan under limited
circumstances. In the event our pension plan is terminated for any reason while
the plan is underfunded, we will incur a liability to the PBGC that may be equal
to the entire amount of the underfunding.

29

Provisions
in our restated certificate of incorporation and restated bylaws, the agreements
governing our indebtedness and Delaware law may discourage a takeover attempt
even if doing so might be beneficial to our shareholders.

Provisions
contained in our restated certificate of incorporation and restated bylaws could
impose impediments to the ability of a third-party to acquire us even if a
change of control would be beneficial to you. Provisions of our restated
certificate of incorporation and restated bylaws impose various procedural and
other requirements, which could make it more difficult for stockholders to
effect certain corporate actions. For example, our restated certificate of
incorporation authorizes our board of directors to determine the rights,
preferences, privileges and restrictions of unissued series of preferred stock,
without any vote or action by our stockholders. Thus, our board of directors can
authorize and issue shares of preferred stock with voting or conversion rights
that could adversely affect the voting or other rights of holders of Common
Stock. We are also subject to provisions of Delaware law that prohibit us from
engaging in any business combination with any “interested stockholder,”
meaning, generally, that a stockholder who beneficially owns more than 15% of
Common Stock cannot acquire us for a period of three years from the date this
person became an interested stockholder unless various conditions are met, such
as approval of the transaction by our board of directors. These provisions may
have the effect of delaying or deterring a change of control of our Company, and
could limit the price that certain investors might be willing to pay in the
future for shares of Common Stock.

If a
“fundamental change” (as defined in the indenture governing the 3.25%
convertible senior notes due 2015 (“3.25% Notes”)) occurs, holders of the 3.25%
Notes will have the right, at their option, either to convert their 3.25% Notes
or require us to repurchase all or a portion of their 3.25% Notes, and holders
of the 4.75% convertible senior notes due 2023 and 2.25% convertible senior
notes due 2024 will have the right to require us to repurchase all or a portion
of their notes. In the event of a “make-whole fundamental change” (as defined in
the indenture governing the 3.25% Notes), we also may be required to increase
the conversion rate applicable to any 3.25% Notes surrendered for conversion. In
addition, the indentures for the convertible notes prohibit us from engaging in
certain mergers or acquisitions unless, among other things, the surviving entity
is a U.S. entity that assumes our obligations under the convertible notes.
Certain of our debt instruments impose similar restrictions on us, including
with respect to mergers or consolidations with other companies and the sale of
substantially all of our assets. These provisions could prevent or deter a
third-party from acquiring us even where the acquisition could be beneficial to
you.

We
may not realize all or any of the anticipated benefits from acquisitions we
undertake, as acquisitions entail